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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549



FORM 10-K

(Mark One)ý

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the fiscal year ended December 31, 2009 oro

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the transition period
from                to                .


Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY(Exact name of registrant as specified in its charter)

Kansas

44-0236370(State of Incorporation)

(I.R.S. Employer Identification No.)602 S. Joplin Avenue, Joplin, Missouri

64801(Address of principal executive offices)

(zip code)Registrant's telephone number: (417) 625-5100
Securities registered pursuant to Section 12(b) of the Act:




Title of each class

Name of each exchange on which registeredCommon Stock ($1 par value)
Preference Stock Purchase Rights

New York Stock Exchange
New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
o    No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
o    No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days. Yes ý    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
o    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o (Do not check if a
smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No ý

The aggregate market value of the registrant's voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock
Exchange on June 30, 2009, was approximately $566,092,888.

As
of February 5, 2010, 38,300,730 shares of common stock were outstanding.

The
following documents have been incorporated by reference into the parts of the Form 10-K as indicated:

The Company's proxy statement, filed pursuant
to Regulation 14A under the Securities Exchange
Act of 1934, for its Annual Meeting of
Stockholders to be held on April 29, 2010

Part of Item 10 of Part III
All of Item 11 of Part III
Part of Item 12 of Part III
All of Item 13 of Part III
All of Item 14 of Part III




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Table of Contents

TABLE OF CONTENTS



PageForward Looking Statements

3PART IITEM 1.

BUSINESS

5General

5Electric Generating Facilities and Capacity

6Gas Facilities

8Construction Program

9Fuel and Natural Gas Supply

9Employees

12Electric Operating Statistics

13Gas Operating Statistics

14Executive Officers and other Officers of Empire

15Regulation

16Environmental Matters

16Conditions Respecting Financing

17Our Web Site

17ITEM 1A.

RISK FACTORS

18ITEM 1B.

UNRESOLVED STAFF COMMENTS

21ITEM 2.

PROPERTIES

22Electric Segment Facilities

22Gas Segment Facilities

24Other Segment Businesses

24ITEM 3.

LEGAL PROCEEDINGS

24ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

24PART IIITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES

25ITEM 6.

SELECTED FINANCIAL DATA

28ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

29Executive Summary

29Results of Operations

35Rate Matters

45Competition

48Liquidity and Capital Resources

50Contractual Obligations

57Dividends

58Off-Balance Sheet Arrangements

59Critical Accounting Policies

59Recently Issued Accounting Standards

63ITEM 7A.

QUANTATATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

64ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

67ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

139ITEM 9A.

CONTROLS AND PROCEDURES

139ITEM 9B.

OTHER INFORMATION

139PART IIIITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

140ITEM 11.

EXECUTIVE COMPENSATION

140ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS

140ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

141ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

141PART IVITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

142SIGNATURES

148


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FORWARD LOOKING STATEMENTS

Certain matters discussed in this annual report are "forward-looking statements" intended to qualify for the safe harbor from liability
established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters
such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other
regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like "anticipate", "believe", "expect", "project", "objective" or similar
expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements
include:



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All
such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is
not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and
we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

We
caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual
results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

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PART 1

ITEM 1.    BUSINESS

General

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation
organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part
of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the distribution of natural gas in
Missouri. Our other segment consists of our fiber optics business. In 2009, 87.5% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of
water), 11.5% from our gas segment, and 1.0% from our other segment.

The
territory served by our electric operations embraces an area of about 10,000 square miles, located principally in southwestern Missouri, and also includes smaller areas in
southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light industry, agriculture and tourism. Of our total 2009 retail
electric revenues, approximately 89.1% came from Missouri customers, 5.1% from Kansas customers, 3.0% from Oklahoma customers and 2.8% from Arkansas customers.

We
supply electric service at retail to 121 incorporated communities as of December 31, 2009, and to various unincorporated areas and at wholesale to four municipally owned
distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 157,000. We operate under franchises having
original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 53% of our electric operating revenues in 2009 were derived from incorporated communities with
franchises having at least ten years remaining and approximately 17% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our
franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.

Our
electric operating revenues in 2009 were derived as follows:

Residential


41.6
%Commercial


31.4Industrial


15.2Wholesale on-system


4.2Wholesale off-system


3.3Miscellaneous sources*


2.7Other electric revenues


1.6


*primarily
public authorities


Our
largest single on-system wholesale customer is the city of Monett, Missouri, which in 2009 accounted for approximately 3% of electric revenues. No single retail customer
accounted for more than 2% of electric revenues in 2009.

Our
gas operations serve customers in northwest, north central and west central Missouri. We provide natural gas distribution to 44 communities and 310 transportation customers as of
December 31, 2009. The largest urban area we serve is the city of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of
the incorporated communities.
Twenty-four of the franchises have 10 years or more remaining on their term. Although our franchises contain no renewal provisions, since our acquisition we have obtained renewals
of all our expiring gas franchises prior to the expiration dates.

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Our
gas operating revenues in 2009 were derived as follows:

Residential


63.1
%Commercial


27.1Industrial


3.6Other


6.2


No
single retail customer accounted for more than 4% of gas revenues in 2009.

Our
other segment consists of our fiber optics business. As of December 31, 2009, we have 89 fiber customers.

Electric Generating Facilities and Capacity

At December 31, 2009, our generating plants consisted of:

Plant

*Capacity
(megawatts)

Primary FuelAsbury


207

CoalRiverton


286

Coal and Natural GasIatan I (12% ownership)


85
**
CoalState Line Combined Cycle (60% ownership)


300
**
Natural GasEmpire Energy Center


267

Natural GasState Line Unit No. 1


96

Natural GasOzark Beach


16

HydroTotal


1,257


*Based
on summer rating conditions as utilized by Southwest Power Pool.**The
85 and 300 megawatts of Iatan and State Line Combined Cycle, respectively, reflect our allocated shares of the capacity of these plants.


See
Item 2, "Properties  Electric Segment Facilities" for further information about these plants.

We,
and most other electric utilities with interstate transmission facilities, have placed our facilities under the Federal Energy Regulatory Commission (FERC) regulated open access
tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the
Southwest Power Pool Regional Transmission Organization (SPP RTO). See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations 
Competition."

We
currently supplement our on-system generating capacity with purchases of capacity and energy from other sources in order to meet the demands of our customers and the
capacity margins applicable to us under current pooling agreements and National Electric Reliability Council rules. The SPP requires its members to maintain a minimum 12% capacity margin. We have
contracted with Westar Energy for the purchase of 162 megawatts of capacity and energy through May 31, 2010 and have contracted to add 50 megawatts of purchased power beginning in 2010 from the
Plum Point Energy Station discussed below. The amount of capacity purchased under such contracts supplements our on-system capacity and contributes to meeting our current expectations of
future power needs.

In
order to replace the 162 megawatts of capacity and energy from Westar Energy that is expiring May 31, 2010, we entered into contracts to add 200 megawatts of power to our
system. This energy is to come from two new plants that are scheduled to be operational in 2010, with 100 megawatts from the new Plum Point Energy Station and 100 megawatts from the new Iatan 2
generating facility, each of which is

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described
below. Due to the expected in-service delays of Plum Point and Iatan 2, however, we have arranged for sufficient alternative transmission and generating capacity to meet our
expected needs for May 2010 through July 2010. The incremental costs associated with this alternative will not have a material impact on our earnings and will be subject to our fuel adjustment
mechanism.

The
Plum Point Energy Station is a new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Construction began in the spring
of 2006 with completion scheduled for summer 2010. Initially we will own, through an undivided interest, 50 megawatts of the project's capacity for approximately $88.0 million in direct
expenditures, excluding allowance for funds used during construction (AFUDC). We spent $83.8 million through December 31, 2009 and anticipate spending an additional $3.6 million
in 2010 for construction expenses related to our 50 megawatt ownership share of Plum Point Unit 1. All of our actual and estimated construction expenditures exclude AFUDC and property taxes unless
specified otherwise. We also have a long-term (30 year) purchased power agreement for an additional 50 megawatts of capacity and have the option to purchase an undivided ownership
interest in the 50 megawatts covered by the purchased power agreement in 2015. During the third quarter of 2009, we entered into a 15 year capital lease for 54 railcars for our Plum Point
plant.

We
also purchased an undivided ownership interest in the coal-fired Iatan 2 generating facility to be operated by Kansas City Power & Light Company (KCP&L) and located
at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Construction began
in the spring of 2006 with completion scheduled for the fall of 2010. Our share of the Iatan 2 construction expenditures is expected to be in a range of approximately $218 million to
$230 million, excluding AFUDC and property taxes. As a requirement for the air permit for Iatan 2, and to help meet requirements of the Clean Air Interstate Rule (CAIR), additional emission
control equipment was installed on Iatan 1. Our share of the Iatan 1 environmental costs was $54.0 million through December 31, 2009. KCP&L reported the equipment met regulatory
in-service criteria as of April 19, 2009 and it is currently in service.

Our
current capital expenditures budget, discussed below, includes $37.3 million in 2010 and $5.9 million in 2011 for our share of Iatan 2. At December 31, 2009, we
have recorded approximately $192.0 million in construction expenditures on the Iatan 2 project. Of this amount, approximately $22.9 million of property expenditures common to both Iatan
1 and Iatan 2 were in service as of December 31, 2009.

Iatan
2 and Plum Point Unit 1 are important components of a long-term, least-cost resource plan to add approximately 200 megawatts of new coal-fired
generation to our system in 2010. The plan is driven by the continued growth in our service area and the expiration of the Westar Energy purchased power contract described above. The Missouri Public
Service Commission (MPSC) issued an order on August 2, 2005 approving a Stipulation and Agreement (Agreement) with an effective date of August 12, 2005 regarding our Experimental
Regulatory Plan (Plan). The Agreement contains conditions related to some of the infrastructure investments discussed above, including Iatan 2, and environmental investments in Iatan 1, as well as the
150 MW combustion turbine at our Riverton Plant and the installation of Selective Catalytic Reduction (SCR) equipment at the Asbury coal-fired plant. The Riverton Plant combustion turbine
and the Asbury SCR equipment were included in our 2007 Missouri rate case and are now in our Missouri rate base. The other parties to the Agreement include the Missouri Department of Natural
Resources, the MPSC Staff, two of our industrial customers and the Office of the Public Counsel. We were also granted a certificate of convenience and necessity to participate in Iatan 2, and in
connection therewith, obtained approval intended to provide adequate assurance to potential investors to make financial options available to us concerning our investment in Iatan 2.

We
have a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase all of the output from the
approximately 105-megawatt Phase 1 Meridian Wind Farm located in Cloud County, Kansas. The windfarm was declared commercial on

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December 15,
2008. We also have a 20-year contract with Elk River Windfarm, LLC to purchase approximately 550,000 megawatt-hours of energy per year. The windfarm was declared
commercial on December 15, 2005. We do not own any portion of either windfarm.

The
following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated contract years (which run from June 1 to
May 31 of the following year). The capacity ratings we use for our generating units are based on summer rating conditions under SPP guidelines. The portion of the purchased power that may be
counted as capacity from the Elk River Windfarm, LLC and the Cloud County Windfarm, LLC is included in this chart. Because the wind power is an intermittent, non-firm
resource, SPP rating criteria does not allow us to count a substantial amount of the wind power as capacity. See Item 7, "Managements' Discussion and Analysis of Financial Condition and Results
of Operations  Liquidity and Capital Resources."

Contract* Year

Purchased
Power
Commitment***

Anticipated
Owned
Capacity

Total Megawatts2009

177

1257

1434**2010

****106

1407

1513**2011

65

1407

1472**2012

65

1407

1472**2013

65

1407

1472


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The
charges for capacity purchases under the Westar contract referred to above during calendar year 2009 amounted to approximately $16.2 million. Minimum charges for capacity
purchases under the Westar contract total approximately $16.2 million for the period June 1, 2009 through May 31, 2010.

The
maximum hourly demand on our system reached a record high of 1,199 megawatts on January 8, 2010. Our previous winter peak of 1,100 megawatts was established on
December 22, 2008. Our maximum hourly summer demand of 1,173 megawatts was set on August 15, 2007. Our previous summer record peak of 1,159 megawatts was established on July 19,
2006.

Gas Facilities

At December 31, 2009, our principal gas utility properties consisted of approximately 87 miles of transmission mains and
approximately 1,118 miles of distribution mains.

The
following table sets forth the three pipelines that serve our gas customers:

Service Area

Name of PipelineSouth

Southern Star Central Gas PipelineNorth

Panhandle Eastern Pipe Line CompanyNorthwest

ANR Pipeline Company


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Our
all-time peak of 73,271 mcfs was established on January 7, 2010, replacing the previous record of 70,820 mcfs which was set on January 4, 2010.

Construction Program

Total property additions (including construction work in progress), excluding AFUDC, for the three years ended December 31,
2009, amounted to $527.1 million and retirements during the same period amounted to $39.6 million. Please refer to Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations  Liquidity and Capital Resources" for more information.

Our
total capital expenditures, excluding AFUDC and expenditures to retire assets, were $140.8 million in 2009 and for the next three years are estimated for planning purposes to
be as follows:

Estimated Capital Expenditures (amounts in millions)2010

2011

2012

TotalNew electric generating facilities:Iatan 2

$
37.3

$
5.9

$


$
43.2Plum Point Energy Station


3.6








3.6Facilities study








3.0


3.0Additions to existing electric generating facilities:Environmental upgrades  Asbury


4.4


0.1





4.5Other


11.0


13.9


11.8


36.7Electric transmission facilities


9.7


9.1


7.7


26.5Electric distribution system additions


36.0


40.1


40.1


116.2Non-regulated additions


2.9


1.5


1.5


5.9General and other additions


3.8


15.2


4.4


23.4Gas system additions


2.2


4.0


2.0


8.2Total

$
110.9

$
89.8

$
70.5

$
271.2


Construction
expenditures for new generating facilities and additions to our transmission and distribution systems to meet projected increases in customer demand constitute the majority
of the projected capital expenditures for the three-year period listed above.

A
new combustion turbine previously scheduled to be installed by the summer of 2011 is currently delayed until 2015 as our generation regulation needs are being met through a combination
of our existing units and the SPP energy imbalance market.

Estimated
capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction and the
availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in customer requirements, construction
delays, changes in equipment delivery schedules, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from
independent power producers and cogenerators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See
"  Regulation" below and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations  Competition."

Fuel and Natural Gas Supply

Electric Segment

In 2009, 55.1% of our total system input, based on kilowatt-hours generated, was supplied by our steam and combustion turbine
generation units, 1.3% was supplied by our hydro generation, and we

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purchased
the remaining 43.6%. Approximately 69.8% of the total fuel requirements for our generating units in 2009 (based on kilowatt-hours generated) were supplied by coal and approximately 29.8%
supplied by natural gas with fuel oil and tire-derived fuel (TDF), which is produced from discarded passenger car tires, providing the remainder. The amount and percentage of electricity
generated by natural gas decreased in 2009 as compared to 2008 while the amount of energy we purchased increased, primarily reflecting that it was more economical to purchase power during this period
than to produce gas-fired generation and reflecting increased purchases of power under our two contracts with windfarms. We offset the cost of these contracts by purchasing less
higher-priced power from other suppliers or by displacing on-system generation.

Our
Asbury Plant is fueled primarily by coal with oil being used as start-up fuel and TDF being used as a supplement fuel. In 2009, Asbury burned a coal blend consisting of
approximately 86.8% Western coal (Powder River Basin) and 13.2% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31,
2009, we had sufficient coal on hand to supply anticipated requirements at Asbury for up to 95 days, as compared to 96-97 days as of December 31, 2008, depending on
the actual blend ratio within this range.

Our
Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas, petroleum coke and oil. We installed a Siemens V84.3A2 gas combustion turbine
(Unit 12) at our Riverton plant in 2007. Riverton Unit 12 and three other smaller units are fueled by natural gas. During 2009, Riverton Units 7 and 8 burned an estimated blend of approximately
82.1% Western coal (Powder River Basin) and 17.9% petroleum coke on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. Riverton Unit 7 requires a minimum
amount of blend fuel to operate, while Riverton Unit 8 can burn 100% Western coal or a mix of Western and blend fuel. Based on these assumptions, we had sufficient coal as of December 31, 2009
to run 36 days on both units as compared to 43 days as of December 31, 2008.

We
have secured 98% of our anticipated coal requirements for 2010, 59% for 2011, 28% for 2012 and 30% for 2013 through a combination of contracts and binding proposals. All of the
Western coal is shipped to the Asbury Plant by rail, a distance of approximately 800 miles, under a five-year contract with the Burlington Northern and Santa Fe Railway Company (BNSF) and
the Kansas City Southern Railway Company which expires on June 29, 2010. We are currently in the process of selecting a vendor to provide future rail service. The overall delivered price of
coal is expected to be slightly higher in 2010 than in 2009 due to increased market costs. Riverton receives its Western inventory from the coal transported by train to the Asbury Plant which is then
transported by truck to Riverton.

We
currently lease one aluminum unit train on a full time basis and a second set is leased on an interim basis to deliver Western coal to the Asbury Plant. During the third quarter of
2009, we entered into a 15 year lease agreement for 54 railcars for our Plum Point plant, which is scheduled to be completed in the summer of 2010.

Unit
1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by KCP&L, a subsidiary of Great Plains Energy, Inc. and us, with our share of
ownership being 12%. KCP&L is the operator of this plant and is responsible for arranging its fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet 95%
of Iatan's requirements for 2010 and approximately 40% for 2011, 40% for 2012, 40% for 2013 and 25% for 2014. The coal is transported by rail under a contract with BNSF Railway, which expires on
December 31, 2010.

Our
Energy Center and State Line combustion turbine facilities (not including the State Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by
natural gas with oil also available for use primarily as backup. Based on kilowatt hours generated during 2009, Energy Center generation was 99.8% natural gas with the remainder being fuel oil, and
essentially all of the State Line Unit 1 generation came from natural gas. As of December 31, 2009, oil inventories were sufficient for approximately 2 days of full load operation on
Units No. 1, 2, 3 and 4 at the Energy Center and 5 days of

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full
load operation for State Line Unit No. 1. As typical oil usage is minimal, these inventories are sufficient for our current requirements. Additional oil will be purchased as needed.

We
have firm transportation agreements with Southern Star Central Pipeline, Inc. with original expiration dates of July 31, 2016, for the transportation of natural gas to
the SLCC. This date is adjusted for periods of contract suspension by us during outages of the SLCC. This transportation agreement can also supply natural gas to State Line Unit No.1, the Energy
Center or the Riverton Plant, as elected by us on a secondary basis. We also have a precedent agreement with Southern Star, which provides additional transportation capability until 2022. This
contract provides firm transport to the sites listed above that previously were only served on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural
gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder
contracts, interruptible transport, or delivered to the plants by others. The majority of our physical natural gas supply requirements will be met by short-term forward contracts and spot
market purchases. Forward natural gas commodity prices and volumes are hedged several years into the future in accordance with our Risk Management Policy in an attempt to lessen the volatility in our
fuel expenditures and gain predictability.

We
have signed an agreement with Southern Star to purchase one million Dths of firm gas storage service capacity for a period of five years beginning in April 2011. The reservation
charge for this storage capacity is approximately $1.1 million annually. This storage capacity will enable us to better manage our natural gas commodity and transportation needs for our
electric segment.

The
following table sets forth a comparison of the costs, including transportation and other miscellaneous costs, per million Btu of various types of fuels used in our electric
facilities:

Fuel Type/Facility

2009

2008

2007Coal  Iatan

$
1.186

$
1.070

$
0.978Coal  Asbury


1.763


1.577


1.432Coal  Riverton


1.768


1.724


1.548Natural Gas


7.376


6.909


7.050Oil


14.318


16.721


14.870


Our
weighted average cost of fuel burned per kilowatt-hour generated was 3.1698 cents in 2009, 3.1307 cents in 2008 and 3.2197 cents in 2007.

Gas Segment

In June 2007, we acquired 10,000 MMBtus per day of firm transportation from Cheyenne Plains Pipeline Company so that up to 75% of our
natural gas purchases going forward could come from the Rocky Mountain gas area. Cheyenne Plains interconnects with all of the interstate pipelines listed below that feed our market area.

We
have agreements with many of the major suppliers in both the Midcontinent and Rocky Mountain regions that provide us with both supply and price diversity. We expanded our supplier
base in 2008 and will continue to do so to enhance supply reliability as well as provide for increased price competition.

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The
following table sets forth the current costs, including storage, transportation and other miscellaneous costs, per mcf of gas used in our gas operations:

Service Area

Name of Pipeline

2009

2008

2007South

Southern Star Central Gas Pipeline

$
7.8475

$
8.9898

$
8.2967North

Panhandle Eastern Pipe Line Company


7.4055


8.3207


7.9568Northwest

ANR Pipeline Company


7.1160


8.0716


7.0551Weighted average cost

$
7.6395

$
8.6964

$
8.0534


Employees

At December 31, 2009, we had 730 full-time employees, including 54 employees of EDG. 328 of the EDE employees are
members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On May 9, 2007, the Local 1474 IBEW voted
to ratify a new five-year agreement effective retroactively to November 1, 2006, the expiration date of the last contract. At December 31, 2008, 26 of the EDG employees were
members of Local 814 of the IBEW and 8 EDG employees were members of Local 695 of the IBEW. Effective January 1, 2009, both of these locals were merged into Local 1464 of the IBEW, of which 36
EDG employees were members at December 31, 2009. Local 814 of the IBEW and Local 695 of the IBEW had both previously ratified a three-year contract with EDG which expired on
May 31, 2009. In June 2009, Local 1464 of the IBEW ratified a new four-year agreement with EDG effective June 1, 2009.

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ELECTRIC OPERATING STATISTICS(1)

2009

2008

2007

2006

2005Electric Operating Revenues (000's):Residential

$
180,404

$
179,293

$
174,584

$
159,381

$
149,176Commercial


135,800


132,888


129,035


115,059


106,093Industrial


65,983


67,353


67,712


64,820


59,593Public authorities(2)


11,411


10,876


9,933


8,892


8,464Wholesale on-system


18,199


19,229


18,444


17,561


16,582Miscellaneous(3)


6,814


6,976


5,703


4,605


4,833Interdepartmental


178


154


123


101


101Total system


418,789


416,769


405,534


370,419


344,842Wholesale off-system


14,344


29,697


19,627


12,234


14,139Total electric operating revenues(4)


433,133


446,466


425,161


382,653


358,981Electricity generated and purchased (000's of kWh):Steam


2,259,304


2,228,716


2,074,323


2,589,360


2,446,528Hydro


76,733


32,601


71,360


22,673


62,325Combustion turbine


926,934


1,480,729


1,427,298


955,856


1,453,297Total generated


3,262,971


3,742,046


3,572,981


3,567,889


3,962,150Purchased


2,516,702


2,440,246


2,373,282


2,065,991


1,684,657Total generated and purchased


5,779,673


6,182,292


5,946,263


5,633,880


5,646,807Interchange (net)


(568
)

(436
)

(940
)

(173
)

(126
)Total system input


5,779,105


6,181,856


5,945,323


5,633,707


5,646,681Maximum hourly system demand (Kw)


1,085,000


1,152,000


1,173,000


1,159,000


1,087,000Owned capacity (end of period) (Kw)


1,257,000


1,255,000


1,255,000


1,102,000


1,102,000Annual load factor (%)


55.38


54.29


53.39


52.50


55.59Electric sales (000's of kWh):Residential


1,866,473


1,952,869


1,930,493


1,898,846


1,881,441Commercial


1,579,832


1,622,048


1,610,814


1,547,077


1,485,034Industrial


992,165


1,073,250


1,110,328


1,145,490


1,106,700Public authorities(2)


121,816


122,375


115,109


111,204


111,245Wholesale on-system


332,061


344,525


342,347


337,658


328,803Total system


4,892,347


5,115,067


5,109,091


5,040,275


4,913,223Wholesale off-system


515,899


688,203


459,665


303,493


353,138Total Electric Sales


5,408,246


5,803,270


5,568,756


5,343,768


5,266,361Company use (000's of kWh)(5)


9,088


9,209


9,369


9,324


10,263kWh losses (000's of kWh)


361,771


369,377


367,198


280,615


370,157Total System Input


5,779,105


6,181,856


5,945,323


5,633,707


5,646,781Customers (average number):Residential


141,206


140,791


139,840


137,689


134,724Commercial


24,412


24,532


24,330


24,035


23,684Industrial


355


361


362


370


365Public authorities(2)


1,995


1,935


1,927


1,907


1,837Wholesale on-system


4


4


4


4


4Total System


167,972


167,623


166,463


164,005


160,614Wholesale off-system


19


22


20


20


17Total


167,991


167,645


166,483


164,025


160,631Average annual sales per residential customer (kWh)


13,218


13,871


13,805


13,791


13,965Average annual revenue per residential customer

$
1,278

$
1,273

$
1,248

$
1,158

$
1,107Average residential revenue per kWh


9.67
¢

9.18
¢

9.04
¢

8.39
¢

7.93
¢Average commercial revenue per kWh


8.60
¢

8.19
¢

8.01
¢

7.44
¢

7.14
¢Average industrial revenue per kWh


6.65
¢

6.28
¢

6.10
¢

5.66
¢

5.38
¢


(1)See
Item 6, "Selected Financial Data" for additional financial information regarding Empire.(2)Includes
Public Street & Highway Lighting and Public Authorities.(3)Includes
transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.(4)Before
intercompany eliminations.(5)Includes
kWh used by Company and Interdepartmental.


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Table of Contents

GAS OPERATING STATISTICS(1)

2009

2008

2007

2006(2)Gas Operating Revenues (000's):Residential

$
36,176

$
39,639

$
39,205

$
15,957Commercial


15,552


17,416


16,588


7,127Industrial


2,066


5,069


752


356Public authorities


365


416


373


161Total retail sales revenues


54,159


62,540


56,918


23,601Miscellaneous(3)


221


231


206


93Transportation revenues


2,934


2,667


2,753


1,451Total Gas Operating Revenues


57,314


65,438


59,877


25,145Maximum Daily Flow (mcf)


70,046


66,005


68,379


60,890Gas delivered to customers (000's of mcf sales)(4)Residential


2,687


2,949


2,835


1,101Commercial


1,278


1,397


1,304


559Industrial


218


553


76


32Public authorities


30


35


30


12Total retail sales


4,213


4,934


4,245


1,704Transportation sales


4,330


4,059


4,300


2,150Total gas operating and transportation sales


8,543


8,993


8,545


3,854Company use(4)


3


4


2


Transportation sales (cash outs)








56


56Mcf losses


36


140


8


(70
)Total system sales


8,582


9,137


8,611


3,840Customers (average number):Residential


38,621


39,159


40,315


40,673Commercial


5,038


5,119


5,208


5,399Industrial


25


26


24


26Public authorities


131


127


124


128Total retail customers


43,815


44,431


45,671


46,226Transportation customers


296


272


270


252Total gas customers


44,111


44,703


45,941


46,478


(1)See
Item 6, "Selected Financial Data" for additional financial information regarding Empire.(2)2006
revenues and mcf sales represent the months of June through December 2006.(3)Primarily
includes miscellaneous service revenue and late fees.(4)Includes
mcf used by Company and Interdepartmental mcf.


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Table of Contents

Executive Officers and Other Officers of Empire

The names of our officers, their ages and years of service with Empire as of December 31, 2009, positions held and effective
date of such positions are presented below. All of our officers have been employed by Empire for at least the last five years.

Name

Age at
12/31/09

Positions With the Company

With the Company Since

Officer
SinceWilliam L. Gipson


52

President and Chief Executive Officer (2002), Executive Vice President and Chief Operating Officer (2001), Vice President 
Commercial Operations (1997)


1981


1997Bradley P. Beecher(1)


44

Executive Vice President and Chief Operating Officer  Electric (2010), Vice President and Chief Operating Officer 
Electric (2006), Vice President  Energy Supply (2001), General Manager  Energy Supply (2001)


2001


2001Harold Colgin


60

Vice President  Energy Supply (2006), General Manager  Energy Supply (2006), Plant Manager, Asbury Plant (1995)


1972


2006Ronald F. Gatz


59

Vice President and Chief Operating Officer  Gas (2006), Vice President  Strategic Development (2002), Vice
President  Nonregulated Services (2001), General Manager  Nonregulated Services (2001)


2001


2001Gregory A. Knapp(2)


58

Vice President  Finance and Chief Financial Officer (2002), General Manager  Finance (2002)


2002


2002Michael E. Palmer


53

Vice President  Commercial Operations (2001), General Manager  Commercial Operations (2001), Director of Commercial
Operations (1997)


1986


2001Kelly S. Walters(3)


44

Vice President  Regulatory and Services (2006), General Manager  Regulatory and General Services (2005), Director of
Regulatory and Planning (2001)


2001


2006Janet S. Watson


57

Secretary  Treasurer (1995)


1994


1995Laurie A. Delano(4)


54

Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005), Director of Financial Services
(2002)


2002


2005


(1)Bradley
P. Beecher was previously with Empire from 1988 to 1999 and held the positions of Director of Production Planning and Administration (1993) and
Director of Strategic Planning (1995). During the period from 1999 to 2001, Mr. Beecher served as the Associate Director of Marketing and Strategic Planning for the Energy Engineering and
Construction Division of Black & Veatch.(2)Gregory
A. Knapp was previously with Empire from 1978 to 2000 and held the position of Controller and Assistant Treasurer (1983). During the period from
2000 to 2002, Mr. Knapp served as Controller for the Missouri Department of Transportation.(3)Kelly
S. Walters was previously with Empire from 1988 to 1998 and held the position of Director of Internal Auditing (1997  1998). Prior
to rejoining Empire, she was Director of Financial Services of Crowder College.(4)Laurie A.
Delano was previously with Empire from 1979 to 1991 and held the position of Director of Internal Auditing (1983-1991).
Immediately prior to rejoining Empire, she was with Lozier Corporation, a store fixture manufacturing company, from 1997 to 2002, where she served as Plant Controller.


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Table of Contents

Regulation

Electric Segment

General.As a public utility, our electric segment operations are subject to the jurisdiction of the MPSC, the State Corporation
Commission of the
State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission (APSC) with respect to services and facilities, rates and charges, regulatory accounting,
valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities.
The KCC also has jurisdiction over the issuance of all securities because we are a regulated utility incorporated in Kansas. Our transmission and sale at wholesale of electric energy in interstate
commerce and our facilities are also subject to the jurisdiction
of the FERC, under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of
such facilities and accounting matters. See discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations  Competition."

During
2009, approximately 90.9% of our electric operating revenues was received from retail customers. Sales subject to FERC jurisdiction represented approximately 8.0% of our electric
operating revenues during 2009 with the remaining 1.1% being from miscellaneous sources. The percentage of retail revenues derived from each state follows:

Missouri


89.1
%Kansas


5.1Oklahoma


3.0Arkansas


2.8


Rates.See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations  Rate
Matters"
for information concerning recent electric rate proceedings.

Fuel Adjustment Clauses.Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs without the need
for a general
rate proceeding. Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri (effective September 1, 2008), Oklahoma and Kansas (effective January 1, 2006)
and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual
basis.

Gas Segment

General.As a public utility, our gas segment operations are subject to the jurisdiction of the MPSC with respect to services and
facilities, rates
and charges, regulatory accounting, valuation of property, depreciation and various other matters. The MPSC also has jurisdiction over the creation of liens on property to secure bonds or other
securities.

Purchased Gas Adjustment (PGA).The PGA clause allows EDG to recover from our customers, subject to routine regulatory review, the cost
of purchased
gas supplies, including costs associated with our use of natural gas financial instruments to hedge the purchase price of natural gas and related carrying costs. This PGA clause allows us to make rate
changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

Environmental Matters

See Note 11 to the consolidated financial statements for information regarding environmental matters.

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Table of Contents

Conditions Respecting Financing

Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage),
and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage
bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined
in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first
mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2009, would permit us to issue approximately
$239.9 million of new first mortgage bonds based on this test at an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds
must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2009, we had retired bonds and net property additions which would enable the issuance
of at least $644.8 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2009, we believe we are in compliance with all restrictive covenants
of the EDE Mortgage.

Under
our Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in our Restated Articles) for a
specified twelve-month period is at least 11/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred
stock to be outstanding immediately after the issuance of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is outstanding, the amount of unsecured
indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock. Accordingly, the restriction in our
Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.

The
EDG Indenture of Mortgage and Deed of Trust, dated as of June 1, 2006, as amended and supplemented (the EDG Mortgage) contains a requirement that for new first mortgage bonds
to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a
limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after
giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for
the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2009, this test would not allow us to issue new first mortgage bonds.

See
Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations  Liquidity and Capital Resources."

Our Web Site

We maintain a web site at www.empiredistrict.com. Our annual report on Form 10-K, quarterly reports on
Form 10-Q, current reports on form 8-K and related amendments are available free of charge through our web site as soon as reasonably practicable after such
reports are filed with or furnished to the SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our Code of Ethics for the Chief Executive Officer and
Senior Financial Officer, the charters for our Audit Committee, Compensation Committee and Nominating/Corporate Governance Committee, our Procedures for Reporting Complaints on Accounting, Internal
Accounting Controls and Auditing Matters, our Procedures for Communicating with Non-Management Directors and our Policy and Procedures with Respect to Related Person Transactions can also
be found on our web site. All of these documents are available in print to any interested party who requests them. Our web site and the information contained in it and connected to it shall not be
deemed incorporated by reference into this Form 10-K.

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Table of Contents

ITEM 1A.    RISK FACTORS

Investors should review carefully the following risk factors and the other information contained in this Form 10-K.
The risks we face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely
affect our financial position, results of operations and liquidity.

Readers
are cautioned that the risks and uncertainties described in this Form 10-K are not the only ones facing Empire. Additional risks and uncertainties that we are
not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations (including our ability to pay
dividends on our common stock) could suffer if the concerns set forth below are realized.

Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

Currently, our corporate credit ratings and the ratings for our securities are as follows:

Fitch

Moody's

Standard & Poor'sCorporate Credit Rating

n/r*

Baa2

BBB-EDE First Mortgage Bonds

BBB+

Baa1

BBB+Senior Notes

BBB

Baa2

BBB-Trust Preferred Securities

BB+

Baa3

BBCommercial Paper

F2

P-2

A-3Outlook

Negative

Negative

Stable


*Not
rated.


The
ratings indicate the agencies' assessment of our ability to pay interest, distributions and principal on these securities. A rating is not a recommendation to purchase, sell or hold
securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. In addition, a downgrade in
our senior unsecured long-term debt rating would result in an increase in our borrowing costs under our bank credit facility. If any of our ratings fall below investment grade (investment
grade is defined as Baa3 or above for Moody's and BBB- or above for Standard & Poor's and Fitch), our ability to issue short-term debt, commercial paper or other
securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on our business, financial condition
and results of operations. In addition, any actual downgrade of our commercial paper rating from Moody's or Fitch, may make it difficult for us to issue commercial paper. To the extent we are unable
to issue commercial paper, we will need to meet our short-term debt needs through borrowings under our revolving credit facility, which may result in higher costs.

We
cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in
its judgment, circumstances in the future so warrant.

We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of
operations.

The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers,
(2) weather, (3) customer growth and (4) general economic conditions. Of the factors driving revenues, weather has the greatest short-term effect on the demand for
electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. In addition, changes in customer demand due to downturns in the economy could
reduce our revenues.

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Table of Contents

The
primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expenses, (2) maintenance and repairs expense, including repairs
following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Although we generally recover these expenses
through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases.

The
primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of
natural gas and interstate pipeline transportation charges and (5) general economic conditions. Because natural gas is heavily used for residential and commercial heating, the demand for this
product depends heavily upon weather patterns throughout our natural gas service territory and a significant amount of our natural gas revenues are recognized in the first and fourth quarters related
to the heating seasons. Accordingly, our natural gas operations have historically generated less revenues and income when weather conditions are warmer in the winter.

The
primary driver of our gas operating expense in any period is the price of natural gas.

Significant
increases in electric and gas operating expenses or reductions in electric and gas operating revenues may occur and result in a material adverse effect on our business,
financial condition and results of operations.

We are exposed to factors that can increase our fuel and purchased power expenditures, including disruption in deliveries of coal or natural gas, decreased output from our
power plants, failure of performance by purchased power counterparties and market risk in our fuel procurement strategy.

Fuel and purchased power costs are our largest expenditures. Increases in the price of coal, natural gas or the cost of purchased power
will result in increased electric operating expenditures.

We
depend upon regular deliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for the facility which supplies us with purchased power under our contract with
Westar Energy. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by train. Production problems in these mines, railroad transportation
or congestion problems, or unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing us to implement coal conservation and supply replacement
measures to retain adequate reserve inventories at our facilities. These measures could include some or all of the following: reducing the output of our coal plants, increasing the utilization of our
higher-cost gas-fired generation facilities, purchasing power from other
suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures could result in increased fuel and
purchased power expenditures.

With
the addition of the Missouri fuel adjustment mechanism effective September 1, 2008, we now have a fuel cost recovery mechanism in all of our jurisdictions, which
significantly reduces our net income exposure to the impact of the risks discussed above. However, cash flow could still be impacted by these increased expenditures. We are also subject to prudency
reviews which could negatively impact our net income if a regulatory commission would conclude our costs were incurred imprudently.

We
have also established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs and manage cost and pricing uncertainty. Within this
activity, we may incur losses from these contracts. By using physical and financial instruments, we are exposed to credit risk and market risk. Market risk is the exposure to a change in the value of
commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed
determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be
reclassified to fuel expense and recovered or refunded to the customer

19

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Table of Contents

through
our fuel adjustment mechanisms. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms.

We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.

In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a
purchased gas adjustment provision. Our purchased gas adjustment provision is regularly reviewed by the MPSC. In addition to reviewing our adjustments to customer rates, the MPSC reviews our costs for
prudency as well. To the extent the MPSC may determine certain costs were not incurred prudently, it could adversely affect our gas segment earnings and cash flows. In addition, increases in natural
gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in natural gas costs may also result in
lower usage by customers unable to switch to alternate fuels. Such disallowed costs or customer losses could have a material adverse effect on our business, financial condition and results of
operations.

We are subject to regulation in the jurisdictions in which we operate.

We are subject to comprehensive regulation by federal and state utility regulatory agencies, which significantly influences our
operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including the
rates that we can charge customers, siting and construction of facilities, pipeline safety and compliance, customer service and our ability to recover increases in our fuel and purchased power costs.

The
FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction
over many of our other activities.

Information
concerning recent filings requesting increases in rates and related matters is set forth under Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations  Rate Matters."

We
are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Despite our requests, these regulatory commissions have sole
discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our utility customers. They have similar authority with respect to our recovery of increases in our
fuel and purchased power costs. If our costs increase and we are unable to recover increased costs through base rates or fuel adjustment clauses, or if we are unable to fully recover our investments
in new facilities, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our
results of operations.

Operations risks may adversely affect our business and financial results.

The operation of our electric generation, and electric and gas transmission and distribution systems involves many risks, including
breakdown or failure of expensive and sophisticated equipment, processes and personnel performance; operating limitations that may be imposed by equipment conditions, environmental or other regulatory
requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; and catastrophic events such as fires, explosions, severe weather or other similar
occurrences.

We
have implemented training, preventive maintenance and other programs, but there is no assurance that these programs will prevent or minimize future breakdowns, outages or failures of
our generation facilities. In those cases, we would need to either produce replacement power from our other facilities or

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Table of Contents

purchase
power from other suppliers at potentially volatile and higher cost in order to meet our sales obligations.

These
and other operating events may reduce our revenues, increase costs, or both, and may materially affect our results of operations, financial position and cash flows.

Financial market disruptions may increase financing costs, limit access to the credit markets or cause reductions in investment values in our pension plan assets.

General market declines in 2008 and early 2009, resulting in part from the sub-prime mortgage issues, have generally
reduced access to the capital markets. We estimate our capital expenditures to be $110.9 million in 2010. Although we believe it is unlikely we will have difficulty accessing the markets for
the capital needed to complete these projects, financing costs could fluctuate. Market conditions in 2008 negatively impacted the return on our pension plan and Other Postretirement Benefits (OPEB)
assets in 2008. Our net pension and OPEB liability increased $68.7 million in 2008. The market recovered in 2009, however our costs also increased, resulting in a $0.7 million increase
in our 2009 net pension and OPEB liability. We expect to be required to fund approximately $15.2 million in 2010 for pension and OPEB liabilities. Future market declines could result in
increased pension and OPEB liabilities and funding obligations.

The cost and schedule of construction projects may materially change.

We have entered into an agreement to purchase an undivided interest in 50 megawatts (7.5% ownership interest) of the Plum Point Energy
Station's new 665-megawatt, coal-fired generating facility, scheduled for completion in the summer of 2010. We have also entered into an agreement with KCP&L to purchase an
undivided ownership interest in the coal-fired Iatan 2 generating facility, scheduled for completion in the fall of 2010. We will own 12%, or approximately 100 megawatts, of the
850-megawatt unit.

There
are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their
contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than currently planned, the scope and timing
of projects may change, and other events beyond our control, including the failure of one or more of the generation plant co-owners to pay their share of construction, operations and
maintenance costs, may occur that may materially affect the schedule, budget, cost and performance of these projects. To the extent the completion of these projects is delayed, we expect that the
timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed. Costs associated with these projects will also be subject to prudency review by
regulators as part of future rate case filings.

We are subject to environmental laws and the incurrence of environmental liabilities which may adversely affect our business, financial condition and results of operations.

We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply
with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations
of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and
our existing facilities. Compliance with current and future air emission standards (such as those limiting emission levels of sulfur dioxide (SO2) and nitrogen oxide (NOx) and, potentially, carbon
dioxide (CO2)) has required, and may in the future require, significant environmental expenditures. Although we have historically recovered such costs through our rates, there can be no assurance that
we will recover all, or any part of, such increased costs in future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material
adverse effect on our business, financial condition and results of operations.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.    PROPERTIES

Electric Segment Facilities

At December 31, 2009, we owned generating facilities with an aggregate generating capacity of 1,257 megawatts.

Our
principal electric baseload generating plant is the Asbury Plant with 207 megawatts of generating capacity. The plant, located near Asbury, Missouri, is a coal-fired
generating station with two steam turbine generating units. The plant presently accounts for approximately 16% of our owned generating capacity and in 2009 accounted for approximately 41.2% of the
energy generated by us. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring.
Approximately every fifth year, the maintenance outage is scheduled to be extended to a total of six weeks to permit inspection of the Unit No. 1 turbine. The last such outage took place in the
fall of 2007. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was last inspected in 2001. As of December 31, 2009, Unit No. 2 has
operated approximately 2,862 hours since its last turbine inspection in 2001. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel expenditures
associated with replacement energy, which is now likely to be recovered through our fuel adjustment clauses.

Our
generating plant located at Riverton, Kansas, has two steam-electric generating units (Units 7 and 8) with an aggregate generating capacity of 92 megawatts and four
gas-fired combustion turbine units (Units 9, 10, 11 and 12) with an aggregate generating capacity of 194 megawatts. The steam-electric generating units burn coal as a primary fuel
and have the capability of burning natural gas. We installed a Siemens V84.3A2 combustion turbine (Unit 12) at our Riverton plant in 2007 with a summer rated capacity of 150 megawatts. It began
commercial operation on April 10, 2007.

We
own a 12% undivided interest in the coal-fired Unit No. 1 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City,
Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit
covers the entire Iatan Generating Station and includes the existing Unit No. 1 and Unit No. 2, currently under construction. Iatan 1 began a planned major maintenance outage on
October 18, 2008 which included activities ranging from a turbine upgrade and generator rewind to the tie-in of the new air quality control systems. Once all the outage work was
complete, start-up and commissioning activities began in late January. In early February, vibration issues with the upgraded high pressure turbine were encountered requiring the turbine to
be shipped off-site for repairs, delaying the unit's return to service until the second quarter of 2009. KCP&L reported the emission control equipment had met regulatory
in-service criteria as of April 19, 2009 and it is currently in service. We are entitled to 12% of the unit's available capacity, currently 85 megawatts, and are obligated to pay
for that percentage of the operating costs of the unit. KCP&L operates the unit for the joint owners.

Our
State Line Power Plant, which is located west of Joplin, Missouri, consists of Unit No. 1, a combustion turbine unit with generating capacity of 96 megawatts and a Combined
Cycle Unit with generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat
recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc., which owns
the remaining 40% of the unit. Westar reimburses us for a percentage of the operating costs per our joint ownership agreement stipulations. We are the operator of the Combined Cycle Unit. All units at
our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil. Unit No. 1 had its first major inspection from
September 7, 2006 until December 20, 2006.

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We
have four combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 267 megawatts. These peaking units operate
on natural gas, as well as oil.

Our
hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a
long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the
Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be
increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the
lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it
with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act requires the Southwest Power Administration (SWPA), in
coordination with us and our relevant public service commissions, to determine our economic detriment.

The
SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime
replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be calculated using the
method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the
White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA's determination at that time resulted in a present value for the estimated future lifetime replacement
costs of the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8, 2009, the SWPA published a draft addendum to its January 2009 Final Determination Report
documenting proposed changes to the SWPA's methodology, including the inclusion of an additional discount rate source to be used by the SWPA in determination of the present value of the losses.
Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA's Draft Addendum to its Final Determination
results in a present value of $22.3 million for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on
the new methodology included in the draft addendum but cannot predict the final outcome. Originally, the Appropriations Act had a provision for the Army Corp of Engineers to provide a one time payment
to us for lost energy production. This provision was revised in October 2009 to allow the SWPA to pay for damages through a special disbursement account. Under the revised law, payments must be made
annually by SWPA in an amount of at least $5 million until the total damages are reimbursed.

At
December 31, 2009, our transmission system consisted of approximately 22 miles of 345 kV lines, 434 miles of 161 kV lines, 745 miles of 69 kV lines and 81 miles of 34.5 kV
lines. Our distribution system consisted of approximately 6,905 miles of line.

Our
electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common in the land for the Iatan Generating Station. We own a similar
interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or
owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record
holders of title. Substantially all of our electric segment property, plant and equipment are subject to the EDE Mortgage.

We
also own and operate water pumping facilities and distribution systems consisting of a total of approximately 87 miles of water mains in three communities in Missouri.

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Gas Segment Facilities

At December 31, 2009, our principal gas utility properties consisted of approximately 87 miles of transmission mains and
approximately 1,118 miles of distribution mains.

Substantially
all of our gas transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) under streets, alleys, highways and
other public places, under franchises or other rights; or (3) under private property by virtue of easements obtained from the record holders of title. Substantially all of our gas segment
property, plant and equipment are subject to the EDG Mortgage.

Other Segment

Our other segment consists of our non-regulated business, the leasing of fiber optics cable and equipment (which we also
use in our own utility operations).

ITEM 3.    LEGAL PROCEEDINGS

See Note 11 of "Notes to Consolidated Financial Statements" under Item 8, which description is incorporated herein by
reference.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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Table of Contents

PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is listed on the New York Stock Exchange. On February 5, 2010, there were 5,044 record holders and 31,905
individual participants in security position listings. The high and low sale prices for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share
of quarterly dividends declared and paid on the common stock for each quarter of 2009 and 2008 were as follows:

Price of Common StockDividends Paid Per Share2009

2008High

Low

High

Low

2009

2008First Quarter

$
18.51

$
11.92

$
23.29

$
19.33

$
0.32

$
0.32Second Quarter


16.66


14.19


21.88


18.30


0.32


0.32Third Quarter


19.00


16.44


23.48


18.37


0.32


0.32Fourth Quarter


19.36


17.78


21.60


14.90


0.32


0.32


Holders
of our common stock are entitled to dividends, if, as, and when declared by the Board of Directors, out of funds legally available therefore subject to the prior
rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the
amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2009, our retained earnings balance was $10.1 million (compared
to $13.6 million at December 31, 2008) after paying out $44.8 million in dividends during 2009. A reduction of our dividend per share, partially or in whole, could have an adverse
effect on our common stock price. On February 4, 2010, the Board of Directors declared a quarterly dividend of $0.32 per share on common stock payable March 15, 2010 to holders of record
as of March 1, 2010.

Under
Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which
the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax.
However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the
Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the
FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive
analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial
condition of the utility.

In
addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may
not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock
financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would
exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another
corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to
our shareholders by increasing the basket available to pay dividends by

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$10.75 million,
as described above. As of December 31, 2009, this restriction did not prevent us from issuing dividends.

In
addition, under certain circumstances, our Junior Subordinated Debentures, 81/2% Series due 2031, reflected as a note payable to securitization trust on our balance
sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if:
(1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable
steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred
interest payments on the Junior Subordinated Debentures, 81/2% Series due 2031 or given notice of a deferral of interest payments. As of December 31, 2009, there were no such
restrictions on our ability to pay dividends.

During
2009, no purchases of our common stock were made by or on behalf of us.

Participants
in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at
an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their
stock certificates.

Our
shareholders rights plan, which expires July 25, 2010, provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock
owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price
of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an Acquiring
Person acquires 10% or more of our common stock or if certain other events occur. See Note 5 of "Notes to Consolidated Financial Statements" under Item 8 for additional information. In
addition, we have stock
based compensation programs which are described in Note 4 of "Notes to Consolidated Financial Statements" under Item 8.

Our
By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share
acquisitions of our capital stock.

See
Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding our common stock and equity compensation plans.

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Table of Contents

The
following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2004, in our common stock and similar investments
made in the securities of the companies in the Standard & Poor's 500 Composite Index (S&P 500 Index) and the Standard & Poor's Electric Utilities Index (S&P Electric Utility). The
graph and table assume that dividends were reinvested when received.

GRAPHIC

Total Return Analysis

12/31/2004

12/31/2005

12/31/2006

12/31/2007

12/31/2008

12/31/2009The Empire District Electric Company

$
100.00

$
94.87

$
121.87

$
118.68

$
97.76

$
112.38S&P Electric Utilities Index

$
100.00

$
118.05

$
145.11

$
178.67

$
132.50

$
136.98S&P 500 Index

$
100.00

$
104.91

$
121.48

$
128.16

$
80.74

$
102.11


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ITEM 6.    SELECTED FINANCIAL DATA(in thousands, except per share amounts)(1)

2009

2008

2007

2006(2)

2005Operating revenues

$
497,168

$
518,163

$
490,160

$
412,171

$
362,720Operating income

$
74,495

$
71,012

$
65,566

$
69,821

$
53,920Total allowance for funds used during construction

$
14,133

$
12,518

$
7,665

$
4,255

$
561Income from continuing operations

$
41,296

$
39,722

$
33,181

$
40,029

$
24,944Income (loss) from discontinued operations, net of tax

$


$


$
63

$
(749
)
$
(1,176
)Net income

$
41,296

$
39,722

$
33,244

$
39,280

$
23,768Weighted average number of common shares outstanding  basic


34,924


33,821


30,587


28,277


25,898Weighted average number of common shares outstanding  diluted


34,956


33,860


30,610


28,296


25,941Earnings from continuing operations per weighted average share of common stock  basic and diluted

$
1.18

$
1.17

$
1.09

$
1.42

$
0.96Loss from discontinued operations per weighted average share of common stock  basic and diluted

$


$


$
0.00

$
(0.03
)
$
(0.04
)Total earnings per weighted average share of common stock  basic and diluted

$
1.18

$
1.17

$
1.09

$
1.39

$
0.92Cash dividends per share

$
1.28

$
1.28

$
1.28

$
1.28

$
1.28Common dividends paid as a percentage of net income


108.5
%

109.0
%

117.2
%

91.8
%

139.5
%Allowance for funds used during construction as a percentage of net income


34.2
%

31.5
%

23.1
%

10.8
%

2.4
%Book value per common share (actual) outstanding at end of year

$
15.75

$
15.56

$
16.04

$
15.49

$
15.08Capitalization:Common equity

$
600,150

$
528,872

$
539,176

$
468,609

$
393,411Long-term debt

$
640,156

$
611,567

$
541,880

$
462,398

$
407,786Ratio of earnings to fixed charges


2.15x


2.19x


2.08x


2.60x


2.21xTotal assets

$
1,839,846

$
1,713,846

$
1,473,074

$
1,319,142

$
1,122,030Plant in service at original cost

$
1,718,584

$
1,586,152

$
1,506,234

$
1,380,431

$
1,287,717Capital expenditures (including AFUDC)(3)

$
148,804

$
206,405

$
195,568

$
120,171

$
73,232


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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public
utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide
water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary. It provides natural gas distribution to customers in 44 communities in northwest, north
central and west central Missouri. Our other segment consists of our fiber optics business. During the year ended December 31, 2009, 87.5% of our gross operating revenues were provided from
sales from our electric segment (including 0.4% from the sale of water), 11.5% from the sale of gas and 1.0% from our other segment.

Electric Segment

The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers,
(2) weather, (3) customer growth and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory
Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and
purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Of the factors driving revenues, weather has the
greatest short-term effect on the demand for electricity for our regulated business. Very hot summers and very cold winters increase electric demand, while mild weather reduces demand.
Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions. Customer growth,
which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual electric customer growth to range from approximately 1.1% to 1.5% over the next several
years. Our electric customer growth for the year ended December 31, 2009 was 0.3%. We define electric sales growth to be growth in kWh sales period over period excluding the impact of weather.
The primary drivers of electric sales growth are customer growth and general economic conditions.

The
primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs
following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Historically, fuel and purchased power costs were
the expense items that had the most significant impact on our net income. In our 2007 rate case, the Missouri Public Service Commission (MPSC) authorized a fuel adjustment clause for our Missouri
customers effective September 1, 2008. The MPSC established a base rate for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to
customers of 95% of the changes in fuel and purchased power costs above or below the base. With the addition of the Missouri fuel adjustment mechanism, we now have a fuel cost recovery mechanism in
all of our jurisdictions, which will significantly reduce the impact of fluctuating fuel and purchased power costs on our net income.

Gas Segment

The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather,
(3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge
our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for
rate relief and file for such relief when necessary. A PGA clause is included in our gas rates, which allows us to

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recover
our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and
supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and
earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. Customer growth, which is the growth in the number of customers,
contributes to the demand for gas. Our gas segment customer contraction for the year ended December 31, 2009 was 1.3%, which we believe was due to depressed economic conditions. The rate of gas
customer contraction is expected to level out during the next three years and begin modest growth after 2012. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The
primary drivers of gas sales growth are customer growth and general economic conditions.

The
primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from
our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or cause customers to reduce usage.

Earnings

For the year ended December 31, 2009, basic and diluted earnings per weighted average share of common stock were $1.18 compared
to $1.17 for the year ended December 31, 2008. Third quarter 2009 weather was the coolest summer in the past 30 years, which affected both customer demand and generation needs. The
resulting lower revenues were the primary driver for lower earnings in 2009 as compared to 2008. Lower fuel and purchased power costs, however, mostly offset the decrease in revenues.

The
table below sets forth a reconciliation of basic and diluted earnings per share between 2008 and 2009, which reconciliation is a non-GAAP presentation. The economic
substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of operations on a per share basis
before the impact of additional stock issuances.

We
believe this presentation is useful to investors because the statement of operations does not readily show the EPS impact of the various components, including the effect of new stock
issuances. This could limit the readers' understanding of the reasons for the EPS change from previous years. This information is useful to management, and we believe this information is useful to
investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

This
reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations. We also note that this presentation does
not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance
with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to

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supplement
GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

Earnings Per Share  2008

$
1.17RevenuesElectric on-system

$
0.04Electric off-system and other


(0.30
)Gas


(0.16
)Water


0.00Other


0.01ExpensesElectric fuel and purchased power


0.43Cost of natural gas sold and transported


0.14Regulated  electric segment


(0.02
)Regulated  gas segment


0.00Other segment


0.00Maintenance and repairs


(0.09
)Depreciation and amortization


0.04Other taxes


(0.01
)Interest charges


(0.07
)AFUDC


0.03Change in effective income tax rates


0.00Other income and deductions


(0.01
)Dilutive effect of additional shares issued


(0.02
)Earnings Per Share  2009

$
1.18


Fourth Quarter Results

Earnings for the fourth quarter of 2009 were $7.9 million, or $0.22 per share, as compared to $7.7 million, or $0.23 per
share, in the fourth quarter 2008. Total revenues decreased approximately $10.4 million (7.9%) for the fourth quarter of 2009 as compared to the fourth quarter of 2008 primarily due to milder
weather in October and November of 2009 as compared to 2008. Mostly offsetting the decrease in revenues were decreased fuel and purchased power costs and decreased natural gas costs.

2009 Activities

Regulatory Matters

On November 4, 2009, we filed a request with the Kansas Corporation Commission (KCC) for an annual increase in base rates for
our Kansas electric customers in the amount of $5.2 million, or 24.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1
completed in 2009 and at our Asbury plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007.
We anticipate new rates will go into effect in July 2010.

On
October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%.
This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point
Generating Station. We are currently in discussions about procedures to be used in this case, including the timing of the consideration and rate recovery of our investments in the three generating
facilities and other expenditures. Due to the expected in-service delay of Iatan 2, however, we do not anticipate recovering Iatan 2 costs in this Missouri rate case. We anticipate filing
a rate case at the conclusion of this case to recover the Iatan 2 costs.

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On
June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this
filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. We have entered into a Stipulated
Agreement, which was approved by the MPSC, for an increase of $2.6 million. Pursuant to the Agreement, new rates will go into effect on April 1, 2010.

All
pending applications for rehearing in our 2006 Missouri electric rate case were denied by the MPSC on November 20, 2008. On December 15, 2008, the Office of the Public
Counsel (OPC) filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC's decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a Petition for Writ of
Review on December 19, 2008. These actions were consolidated into one proceeding. Briefs were filed by all parties and oral arguments were held on June 2, 2009. The Cole County Circuit
Court issued a ruling on December 8, 2009, affirming the MPSC's order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

On
May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the
period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a
motion to dismiss, or, in the alternative, motion for more definitive statement. On September 3, 2009, the Jasper County Circuit Court dismissed the petition with prejudice. On
October 7, 2009, the OPC appealed the Jasper County Circuit Court decision to the Missouri Court of Appeals  Southern District. The initial brief was filed by the OPC on
January 11, 2010. We filed a responsive brief on February 5, 2010.

The
MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric
customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went
into effect August 23, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12,
2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC approved our tariff sheets containing our base
rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied
all pending applications for rehearing.

On
October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions
were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on
December 31, 2009, affirming the Commission's Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

For
additional information, see "Rate Matters" below.

Financings

During the fourth quarter of 2009, we issued and sold 2,115,149 shares of our common stock, pursuant to our equity distribution
agreement with UBS Securities LLC (UBS), at an average price per share of $18.51, resulting in proceeds to us of approximately $37.9 million (after payment of approximately
$1.2 million in commissions to the sales agent). Since inception of the program, in the aggregate, we have issued and sold 3,767,909 shares pursuant to the program, resulting in net proceeds to
us of approximately $66.7 million. Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the
program agreement, we may also sell shares to UBS as principal for UBS' own account at a price agreed upon at the time of sale. On

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October 22,
2009, we amended the equity distribution agreement to increase the aggregate offering amount under the program from $60 million to $120 million.

On
March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately
$72.6 million, were used to repay short-term debt incurred, in part, to fund our current construction program.

On
January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement (Credit Agreement) which amends and restates our Amended and Restated Unsecured
Credit Agreement dated March 14, 2006. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the
pricing and fees under the Credit Agreement were amended. Interest on borrowings under the Credit Agreement accrues at a rate equal to, at our option, (i) the highest of (A) the bank's
prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each
case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the Credit Agreement. As of the date hereof, and based on our current credit ratings, the LIBOR
margin under the facility increased from 0.80% to 2.70%. A facility fee is payable quarterly on the full amount of the commitments under the Credit Agreement and a usage fee is payable on the full
amount of the commitments under the Credit Agreement for any period in which we have drawn less than 33% of the total revolving commitments under the Credit Agreement, in each case based on our
current credit ratings. In addition, upon entering into the Credit Agreement, we paid an upfront fee to the revolving credit banks of $900,000 in the aggregate. The aggregate amount of the revolving
commitments remained unchanged at $150 million and there were no other material changes to the terms of the Credit Agreement.

On
March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for
working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit
agreement is in addition to, and has substantially identical covenants and terms as (other than pricing), our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010.
There were no borrowings under the new agreement at December 31, 2009.

Regulatory Plan

On April 19, 2009, we began recording deferred carrying charges associated with environmental upgrades recently completed at our Iatan
1 facility in accordance with our regulatory plan. We deferred $2.7 million in 2009. Construction accounting, for purposes of the regulatory plan, allows us to defer certain charges as
regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. The amounts deferred, which began at
the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be amortized over the life of the plants once they are in our rate base.
The regulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercial operation on April 10, 2007 at our Riverton plant, the environmental upgrades at
Asbury, which were completed in 2008, environmental upgrades at Iatan 1 and the construction of the Iatan 2 facilities. See Note 3 of "Notes to Consolidated Financial Statements".

Iatan 2

On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an
undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Early in the third
quarter of 2009, KCP&L announced its efforts to produce a cost and schedule reforecast primarily to address on-going productivity issues that were negatively impacting the original
schedule and reported the anticipated

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in-service
date for Iatan 2 to be late summer of 2010. Based on a late summer in-service date, we expected base rates reflecting our investment to be in effect in late 2010 as
we filed a request with the MPSC on October 29, 2009, for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%, as discussed
above. However, on January 13, 2010, KCP&L announced that, due to construction delays and unusually cold weather, it currently anticipates that the in-service date of Iatan 2 will
shift approximately two months into the fall of 2010. KCP&L also announced that, as the Iatan 2 project moves into the startup phase, it has commenced a cost and schedule reforecast process for Iatan
2. KCP&L notes that the results will be disclosed when the process is completed, which it currently projects to be in the second half of the first quarter of 2010. Additionally, KCP&L also stated that
it presently believes there will be
no material increase in the estimated construction cost range of Iatan 2. As a result of this delay in the project, we expect that the timing of receipt of the increase in base rates associated with
Iatan 2 will be delayed.

SLCC Generator Failure

On July 3, 2009, the generator on State Line Unit 2-1, one of the combustion turbines at SLCC, failed during
operation. Unit 2-1 represents about 150 megawatts of the 500 megawatts rated output of SLCC, of which we are entitled to 60%, or 300 megawatts. The remainder of SLCC was undamaged and
continued to operate as normal. The cost to replace the turbine was in excess of the $1.5 million insurance deductible on the unit. We expect to recover all the costs from insurance proceeds in
excess of the $1.5 million deductible. The unplanned outage did not have a material financial impact. Unit 2-1 returned to service in October 2009.

Energy Center Engine Failure

On September 28, 2009, we experienced a failure on Energy Center Unit 3, Engine A. The unit returned to 100% operation on
December 23, 2009. This unplanned outage did not have a material financial impact, as almost all of the expenditures were capital replacements and our insurance covered all costs greater than
our $500,000 deductible.

2009 Storm Damage

A major wind storm caused substantial damage to our electric service territory on May 8, 2009. Approximately 83,000 of our
electric customers were without power at the height of the storm. Incremental costs associated with the restoration effort due to the wind storm were approximately $6.0 million, of which
$5.3 million was capitalized as additions to our utility plant and approximately $0.7 million was maintenance expense that was deferred as a regulatory asset as we believe it is probable
that these costs will be recoverable in future electric rate cases.

Ozark Beach Plant

Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a
generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water
Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this,
the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our
electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it with additional
generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act requires the Southwest Power Administration (SWPA), in coordination with us
and our relevant public service commissions, to determine our economic detriment.

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The
SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime
replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be calculated using the
method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the
White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA's determination at that time resulted in a present value for the estimated future lifetime replacement
costs of the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8, 2009, the SWPA published a draft addendum to its January 2009 Final Determination Report
documenting proposed changes to the SWPA's methodology, including the inclusion of an additional discount rate source to be used by the SWPA in determination of the present value of the losses.
Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA's Draft Addendum to its Final Determination
results in a present value of $22.3 million for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on
the new methodology included in the draft addendum but cannot predict the final outcome. Originally, the Appropriations Act had a provision for the Army Corp of Engineers to provide a one time payment
to us for lost energy production. This provision was revised in October 2009 to allow the SWPA to pay for damages through a special disbursement account. Under the revised law, payments must be made
annually by SWPA in an amount of at least $5 million until the total damages are reimbursed.

Gas Storage Contract

We have signed an agreement with Southern Star to purchase one million Dths of firm gas storage service capacity for a period of five
years beginning in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually. This storage capacity will enable us to better manage our natural gas
commodity and transportation needs for our electric segment

Iatan 2 Coal Investment Tax Credits

We are currently working with KCP&L to enter into an agreement with the IRS to receive our share of the $125 million in advanced
coal investment tax credits granted Iatan 2, of which our share amounts to approximately $17.7 million. We cannot predict the timing of the receipt of the credit. However, it would have no
significant income statement impact as the credit, which would reduce our tax payments, would flow to our customers over the life of the plant.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the years 2009, 2008 and 2007.

The
following table represents our results of operations by operating segment for the applicable periods ended December 31:

(in millions)

2009

2008

2007Income from continuing operations:Electric

$
39.1

$
37.4

$
31.8Gas


0.9


1.7


1.0Other


1.3


0.6


0.4Income from continuing operations

$
41.3

$
39.7

$
33.2Income (loss) from discontinued operations








0.0Net income

$
41.3

$
39.7

$
33.2


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Electric Segment

Overview

Our electric segment income for 2009 was $39.1 million as compared to $37.4 million for 2008.

Electric
operating revenues comprised approximately 87.5% of our total operating revenues during 2009. Of these total electric operating revenues, approximately 41.6% were from
residential customers, 31.4% from commercial customers, 15.2% from industrial customers, 4.2% from wholesale on-system customers, 3.3% from wholesale off-system transactions,
2.7% from miscellaneous sources, primarily public authorities and 1.6% from other electric revenues. The percentage of revenues provided from our wholesale off-system transactions has
decreased during 2009 as compared to 2008 primarily due to decreased market demand resulting from milder weather in 2009 and general economic conditions.

The
amounts and percentage changes from the prior periods in kilowatt-hour ("kWh") sales and electric segment operating revenues by major customer class for
on-system and off-system sales were as follows:

kWh Sales
(in millions)Customer Class

2009

2008

% Change*

2008

2007

% Change*Residential


1,866.5


1,952.9


(4.4
)%

1,952.9


1,930.5


1.2
%Commercial


1,579.8


1,622.0


(2.6
)

1,622.0


1,610.8


0.7Industrial


992.2


1,073.3


(7.6
)

1,073.3


1,110.3


(3.3
)Wholesale on-system


332.0


344.5


(3.6
)

344.5


342.3


0.6Other**


123.4


123.8


(0.3
)

123.8


116.8


6.0Total on-system sales


4,893.9


5,116.5


(4.3
)

5,116.5


5,110.7


0.1Off-system


515.9


688.2


(25.0
)

688.2


459.7


49.7Total KWh Sales


5,409.8


5,804.7


(6.8
)

5,804.7


5,570.4


4.2


*Percentage
changes are based on actual kWh sales and may not agree to the rounded amounts shown above.**Other
kWh sales include street lighting, other public authorities and interdepartmental usage.


Electric Segment Operating Revenues
(in millions)Customer Class

2009

2008

% Change*

2008

2007

% Change*Residential

$
180.4

$
179.3


0.6
%
$
179.3

$
174.6


2.7
%Commercial


135.8


132.9


2.2


132.9


129.0


3.0Industrial


66.0


67.4


(2.0
)

67.4


67.7


(0.5
)Wholesale on-system


18.2


19.2


(5.4
)

19.2


18.4


4.3Other**


11.6


11.0


5.1


11.0


10.1


9.7Total on-system revenues


412.0


409.8


0.5


409.8


399.8


2.5Off-system


14.3


29.7


(51.7
)

29.7


19.6


51.3Total revenues from KWh sales


426.3


439.5


(3.0
)

439.5


419.4


4.8Miscellaneous revenues***


6.8


7.0


(2.3
)

7.0


5.7


22.3Total electric operating revenues

$
433.1

$
446.5


(3.0
)
$
446.5

$
425.1


5.0Water revenues


1.8


1.7


(1.0
)

1.7


1.9


(5.1
)Total Electric Segment Operating Revenues

$
434.9

$
448.2


(3.0
)
$
448.2

$
427.0


5.0


*Percentage
changes are based on actual revenues and may not agree to the rounded amounts shown above.**Other
operating revenues include street lighting, other public authorities and interdepartmental usage.***Miscellaneous
revenues include transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.


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The
following table sets forth revenues and expenses relating to off-system transactions (including through the Southwest Power Pool (SPP) energy imbalance
services (EIS) market) for the years ended December 31:

Off-System Electric Transactions(in millions)

2009

2008

2007Energy Imbalance revenues

$
6.2

$
13.1

$
8.8Other revenues


8.1


16.6


10.8Total off-system revenues


14.3


29.7


19.6Energy Imbalance expenses


4.8


9.3


6.2Other expenses


7.0


12.2


7.8Total off-system expenses


11.8


21.5


14.0Net

$
2.5

$
8.2

$
5.6


2009 Compared to 2008

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased approximately 4.3% during 2009 as compared to 2008 with the associated
revenues increasing approximately $2.2 million (0.5%). Weather and other related factors decreased revenues an estimated $20.3 million. Total cooling degree days (the cumulative number
of degrees that the average temperature for each day during that period was above 65°F) for 2009 were 12.3% less than 2008 and 18.7%
less than the 30-year average. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below
65°F) for 2009 were 4.0% less than 2008 and 0.5% less than the 30-year average. Rate changes, primarily the August 2008
Missouri rate increase (discussed below), contributed an estimated $21.9 million to revenues while continued sales growth contributed an estimated $0.6 million. We expect our annual
customer growth to range from approximately 1.1% to 1.5% over the next several years.

Residential
and commercial kWh sales decreased in 2009 primarily due to mild weather during the year. The related revenues increased during 2009 primarily due to the August 2008 Missouri
rate increase and continued sales growth. Industrial kWh sales decreased 7.6% mainly due to a slowdown created by economic uncertainty while the associated revenues decreased 2.0%, reflecting the
economic conditions, partially offset by the Missouri rate increase. On-system wholesale kWh sales and revenues decreased reflecting the general economic conditions and mild weather.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power
Pool (SPP) energy imbalance services (EIS) market. See "  Competition" below. The majority of our off-system sales margins are now included as a component of the fuel
adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows
back to the customer and has little effect on net income.

Revenues
and related expenses were less during 2009 as compared to 2008 primarily due to decreased market demand and lower gas prices that made it more economical for utilities to
generate their own power rather than purchase it. Total purchased power related expenses are included in our discussion of purchased power costs below.

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Table of Contents

Miscellaneous Revenues

Our miscellaneous revenues were $6.8 million during 2009 as compared to $7.0 million during 2008. These revenues are
comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During 2009, total electric segment operating expenses decreased approximately $17.3 million (4.5%) compared to 2008.

Total
fuel and purchased power expenses decreased approximately $22.1 million (10.8%) during 2009 as compared to 2008. The table below is a reconciliation of our actual fuel and
purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for 2009 and 2008.

(in millions)

2009

2008Actual fuel and purchased power expenditures

$
182.1

$
204.1Kansas regulatory adjustments*


0.5


(0.5
)Missouri fuel adjustment deferral*


(2.0
)

0.2Missouri fuel adjustment recovery**


1.7Unrealized (gain)/loss on derivatives


(0.3
)

0.3Total fuel and purchased power expense per income statement

$
182.0

$
204.1


*A
negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.**Currently
being recovered from customers from prior deferral period.


The
overall fuel and purchased power expense decrease primarily reflects the effect of decreased market demand resulting from mild weather in 2009, as well as the effects
of an extended outage at the Asbury plant lasting from the fourth quarter of 2007 into the first quarter of 2008 during which time we relied on purchased power as well as our gas-fired
units to replace our coal-fired generation. The decrease in fuel costs also includes the effect of decreased off-system sales.

Summarized
in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses when compared to 2008. This table incorporates all the
changes mentioned above. As shown below, the largest impacts on fuel and purchased power costs were lower purchased power and natural gas prices and decreased generation by our gas-fired
units.

(in millions)

2008 to 2009 changeCoal (cost)

$
3.8Natural gas (cost)


2.3Purchased power (cost)


(10.1
)Coal generation volume


(0.6
)Natural gas generation volume


(23.1
)Purchased power spot purchase volume


3.0Natural gas  gain on unwind of positions


2.1Other (including fuel adjustments)


0.5TOTAL

$
(22.1
)


Regulated
operating expenses increased approximately $1.0 million (1.6%) during 2009 as compared to 2008 primarily due to increases of $1.5 million in
professional services, $1.2 million in other steam power expense, $0.8 million in general labor costs and $0.6 million in customer accounts expenses (mainly

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Table of Contents

increased
banking fees). These increases were partially offset by decreases of $1.3 million in employee health care expense, $1.1 million in injuries and damages expense,
$0.4 million in pension expense and $0.3 million in regulatory commission expense. We were able to defer an additional $0.6 million in other steam power expense related to Iatan 1
operating costs in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base.

Maintenance
and repairs expense increased approximately $4.5 million (16.4%) during 2009 primarily due to increases of approximately $3.8 million in distribution
maintenance costs (including $2.5 million of
ice storm related amortization), $1.2 million in maintenance and repairs expense at the Asbury plant, $0.3 million in maintenance and repairs expense to the SLCC mainly due to a
maintenance outage in the first quarter of 2009, $0.1 million in maintenance and repairs expense to the Riverton gas units and $0.1 million in maintenance and repairs expense to State
Line Unit No. 1. These increases were partially offset by decreases of $0.6 million in maintenance and repairs expense at the Iatan plant which experienced an outage in the fourth
quarter of 2008 and $0.4 million in maintenance and repairs expense to the coal units at the Riverton plant.

Depreciation
and amortization expense decreased approximately $2.3 million (4.5%) during 2009 primarily due to reduced regulatory amortization resulting from the Missouri rate
case that went into effect August 23, 2008. Other taxes increased approximately $0.8 million due to increased property tax reflecting our additions to plant in service and increased
municipal franchise taxes.

2008 Compared to 2007

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased approximately 0.1% during 2008 as compared to 2007 primarily due to
continued sales growth. Revenues for our on-system customers increased approximately $10.0 million, or 2.5%. Rate changes, primarily the August 2008 Missouri rate increase
(discussed below), contributed an estimated $8.9 million to revenues while continued sales growth contributed an estimated $3.9 million. Weather and other related factors decreased
revenues an estimated $2.8 million.

Residential
and commercial kWh sales increased in 2008 primarily due to continued sales growth while the associated revenues also increased due to the August 2008 Missouri rate increase.
Industrial kWh sales decreased 3.3% mainly due to a slowdown created by economic uncertainty while the associated revenues decreased 0.5%, reflecting the economic conditions, partially offset by the
Missouri rate increase. On-system wholesale kWh sales increased reflecting the continued sales growth discussed above.

Off-System Electric Transactions

Off-system revenues increased during 2008 as compared to 2007 primarily due to sales facilitated by the EIS market that
began on February 1, 2007. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $7.0 million during 2008 as compared to $5.7 million during 2007. These revenues are
comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

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Table of Contents

Operating Revenue Deductions

During 2008, total electric segment operating expenses increased approximately $17.0 million (4.6%) compared to 2007.

Total
fuel and purchased power expenses increased approximately $12.8 million (6.7%) during 2008 as compared to 2007. The table below is a reconciliation of our actual fuel and
purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for 2008 and 2007.

(in millions)

2008

2007Actual fuel and purchased power expenditures

$
204.1

$
191.0Kansas regulatory adjustments*


(0.5
)

0.2Missouri regulatory adjustments*


0.2


Unrealized loss on derivatives


0.3


Total fuel and purchased power expense per income statement

$
204.1

$
191.2


*A
negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.


The
overall fuel and purchased power increase included the effect of increased costs for off-system sales of $7.6 million and the effect of replacement
power for the Asbury and Riverton 8 outages in both years. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the extended outage at
Asbury increased our
expenses by an additional $5.8 million in the first quarter of 2008 (January 1  February 10, 2008). This compares to the impact of the 5-year planned
maintenance outage in 2007 which we estimated added additional expenses of approximately $8.7 million and the extended outage (December 8  December 31, 2007) which
increased expenses an additional $3.5 million.

Summarized
in the table below are our estimated cost and volume changes in the components of fuel and purchased power costs when compared to 2007. This table incorporates all the changes
mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased costs for both purchased power and coal, offset by decreases in natural gas prices and the effect of
the unwinding of future physical natural gas positions in February 2008.

(in millions)

2007 to 2008 changePurchased power (cost)

$
9.6Coal (cost)


4.0Natural gas (cost)


(1.3
)Coal generation volume


2.5Purchased power spot purchase volume


0.4Natural gas generation volume


(0.2
)Natural gas  gain on unwind of positions


(2.1
)Other


(0.1
)TOTAL

$
12.8


Regulated
operating expenses increased approximately $0.8 million (1.4%) during 2008 as compared to 2007 primarily due to increases of $1.4 million in
transmission and distribution expense, $0.8 million in other steam power expense, $0.6 million in injuries and damages expense, $0.4 million in other power expense and
$0.1 million in director and stockholder expense. These increases were partially offset by decreases of $0.9 million in uncollectible accounts expense, $0.7 million in employee
pension expense, $0.7 million in employee health care expense and $0.2 million in professional services.

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Maintenance
and repairs expense decreased approximately $2.9 million (9.6%) during 2008 mainly due to decreases of approximately $4.2 million in distribution maintenance
costs as compared to 2007. In 2007 we incurred $3.9 million of incremental costs (and $1.2 million non-incremental tree
trimming and labor costs in the first quarter of 2007) related to the January 2007 ice storm and $1.5 million of incremental costs related to the December 2007 ice storm. In 2008 we began
amortizing this cost and recognized $1.4 million in maintenance costs. Also contributing to the decrease during 2008 was a $0.5 million decrease in maintenance and repairs expense at the
Asbury plant as compared to the same period in 2007 when there was an extended outage during the fourth quarter, and a $0.4 million decrease in maintenance expense at the Energy Center plant
compared to 2007 when there was a bearing failure in Unit #3 in the second quarter of 2007. These decreases were partially offset by a $0.7 million increase in maintenance and repairs expense
at the SLCC plant due to the extended spring maintenance outage in the second quarter of 2008, a $0.7 million increase in maintenance and repairs expense at the Riverton plant due to the
extended outage on Unit 8 to repair damage to high pressure blades discovered during Riverton's scheduled maintenance outage in May 2008, a $0.5 million increase in transmission expense and a
$0.1 million increase in maintenance costs for the Riverton gas-fired units.

We
recognized a $1.2 million gain in the fourth quarter of 2007 from the sale of our unit train set. We recognized no corresponding gains in 2008.

Depreciation
and amortization expense increased approximately $0.7 million (1.3%) mainly due to a $2.9 million increase in depreciation expense due to increased plant in
service partially offset by a $2.3 million decrease in the amount of regulatory amortization related to the 2008 Missouri electric rate order that is recorded as depreciation expense. Other
taxes increased approximately $0.4 million due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

The following tables detail our natural gas sales and revenues for the periods ended December 31:

Total Gas Delivered to Customers(bcf sales)

2009

2008

% Change

2008

2007

% ChangeResidential


2.69


2.95


(8.9
)%

2.95


2.83


4.0
%Commercial


1.27


1.40


(8.6
)

1.40


1.30


7.2Industrial*


0.22


0.55


(60.5
)

0.55


0.08


628.3Other**


0.03


0.03


(13.3
)

0.03


0.03


20.5Total retail sales


4.21


4.93


(14.6
)

4.93


4.24


16.3Transportation sales*


4.33


4.06


6.7


4.06


4.30


(5.6
)Total gas operating sales


8.54


8.99


(5.0
)

8.99


8.54


5.3


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Operating Revenues and Cost of Gas Sold($ in millions)

2009

2008

% Change

2008

2007

% ChangeResidential

$
36.2

$
39.6


(8.7
)%
$
39.6

$
39.2


1.1
%Commercial


15.5


17.4


(10.7
)

17.4


16.6


5.0Industrial*


2.1


5.1


(59.3
)

5.1


0.7


574.4Other**


0.4


0.4


(12.8
)

0.4


0.4


17.6Total retail revenues

$
54.2

$
62.5


(13.4
)
$
62.5

$
56.9


9.9Other revenues


0.2


0.2


(2.1
)

0.2


0.2


0.5Transportation revenues*


2.9


2.7


10.0


2.7


2.8


(3.1
)Total gas operating revenues

$
57.3

$
65.4


(12.4
)
$
65.4

$
59.9


9.3Cost of gas sold


35.6


42.6


(16.5
)

42.6


37.6


13.3Gas operating revenues overcost of gas in rates

$
21.7

$
22.8


(4.8
)
$
22.8

$
22.3


2.5


*Percentage
change reflects the transfer of a customer from transportation to industrial sales in April 2008 and back to transportation in April 2009 and two
customers switching from industrial sales to transportation in October 2009 after an eight-month suspension.**Other
includes other public authorities and interdepartmental usage.


2009 Compared to 2008

Operating Revenues and bcf Sales

Gas retail sales decreased 14.6% during 2009 as compared to 2008 reflecting milder weather, the switching of customers between
industrial sales and transportation (see footnote above) and the effect of our gas segment customer contraction of 1.3% in 2009. We believe this contraction was due to depressed economic conditions.
We estimate that the rate of gas customer contraction will level out during the next three years and begin modest growth after 2012. Residential and commercial sales decreased during 2009 primarily
due to the milder weather as well as customer contraction. Heating degree days were 9.7% lower than 2008 and 3.9% lower than the 30-year average. Industrial sales decreased during 2009 due
to the transfer of customers between classes mentioned above.

During
2009, gas segment revenues were approximately $57.3 million as compared to $65.4 million in 2008, a decrease of 12.4%. This decrease was largely driven by the
decrease in residential and industrial sales as well as PGA revenue. During 2009, our PGA revenue (which represents the cost of gas
recovered from our customers) was approximately $35.6 million as compared to $42.6 million in 2008, a decrease of approximately $7.0 million. This decrease was largely driven by
the decrease in sales and decreases in the PGAs that went into effect May 15, 2009 and November 13, 2009.

Our
PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated
with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through
the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of December 31, 2009, we had unrecovered
purchased gas costs of $0.4 million recorded as a current regulatory asset and over recovered purchased gas costs of $1.9 million recorded as a regulatory liability.

Operating Revenue Deductions

Total other operating expenses were $10.3 million during 2009 as compared to $10.0 million in 2008, mainly due to a
$0.2 million increase in distribution operation expense and a $0.1 million increase in

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general
labor costs. Our gas segment had net income of $0.9 million in 2009 as compared to $1.7 million in 2008.

2008 Compared to 2007

Operating Revenues and bcf Sales

Gas retail sales increased 16.3%, primarily due to an increase in industrial sales as compared to 2007 and colder weather. Residential
and commercial sales increased during 2008 as compared to 2007 primarily due to colder weather. Heating degree days were 13.5% higher than
2007. Industrial sales increased during 2008 due to the transfer of one large volume interruptible customer from transportation to sales service and the addition of two new large volume interruptible
customers. These increases offset the effect of our gas segment customer contraction of 1.5% in 2008. We believe this contraction was due to higher gas prices and general economic conditions.

During
2008, gas segment revenues were approximately $65.4 million as compared to $59.9 million in 2007, an increase of 9.3%, reflecting the higher sales and higher gas
costs. During 2008, our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $42.6 million as compared to $37.6 million in 2007, an increase of
approximately $5.0 million. This increase was largely driven by the increase in the industrial sales and the effect of higher sales due to weather.

Our
PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated
with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through
the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of December 31, 2008, we had unrecovered
purchased gas costs of $5.6 million recorded as a regulatory asset.

Operating Revenue Deductions

Total other operating expenses were $10.0 million during 2008 as compared to $10.2 million in 2007, a decrease of
$0.2 million. This decrease was mainly due to a $0.8 million decrease in uncollectible accounts, and a $0.6 million decrease in administrative and general expenses, partially
offset by a $0.9 million increase in customer accounts expense and a $0.2 million increase in distribution expense. Our gas segment had net income of $1.7 million in 2008 as
compared to $1.0 million in 2007.

Other Segment

Our other segment consists of our non-regulated business, the leasing of fiber optics cable and equipment (which we are
also using in our own utility operations). See Note 12 of "Notes to Consolidated Financial Statements". The following table represents the results for our other segment for the applicable
periods ended December 31:

(in millions)

2009

2008

2007Revenues

$
5.5

$
5.0

$
3.7Expenses


4.2


4.4


3.3Net income from continuing operations

$
1.3

$
0.6

$
0.4


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Table of Contents

Consolidated Company

Income Taxes

Our consolidated provision for income taxes increased approximately $0.4 million during 2009 as compared to 2008 primarily due
to increased income. Our consolidated provision for income taxes increased approximately $4.7 million during 2008 as compared to 2007 due to rates for 2009 and 2008 being higher as compared to
2007, primarily due to lower tax benefits received from cost of plant retirement expenditures. Our cost of retirement expenditures was unusually high in 2007 due to the ice storms we experienced.
These reduced benefits were partially offset by an increase in the tax effects of equity AFUDC.

The
following table shows our consolidated effective federal and state income tax rates for the applicable periods ended December 31:

2009

2008

2007Consolidated effective federal and state income tax rates


32.5
%

32.5
%

30.3
%


See
Note 9 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding income taxes.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended
December 31. AFUDC increased in 2009 as compared to 2008 and in 2008 as compared to 2007 due to higher levels of construction in each period. See Note 1 of "Notes to Consolidated
Financial Statements" under Item 8.

($ in millions)

2009

2008

2007Allowance for equity funds used during construction

$
6.2

$
5.9

$
2.9Allowance for borrowed funds used during construction


7.9


6.6


4.8Total AFUDC

$
14.1

$
12.5

$
7.7


Total
interest charges on long-term and short-term debt for 2009, 2008 and 2007 are shown below. The increases in long-term debt
interest for 2009 reflect the interest on the $75 million principal amount of first mortgage bonds we issued March 27, 2009. The increases in long-term debt interest for 2009
and 2008, as compared to 2007, also reflect the $90 million principal amount of first mortgage bonds we issued May 16, 2008. The increase in long-term debt interest for 2008
as compared to 2007 also reflects a full year of interest on the $80 million principal amount of first mortgage bonds we issued on March 26, 2007. The decreases in short-term
debt interest primarily reflect lower cost of borrowing.

Interest Charges
($ in millions)2009

2008

Change

2008

2007

ChangeLong-term debt interest

$
42.1

$
36.0


16.8
%
$
36.0

$
31.1


15.8
%Short-term debt interest


1.1


1.9


(39.3
)

1.9


2.9


(37.0
)Note payable to securitization trust interest


4.3


4.3


0.0


4.3


4.3


0.0Iatan 1 deferral*


(1.3
)













Other interest


0.6


1.1


(42.5
)

1.1


1.1


7.8Total interest charges

$
46.8

$
43.3


8.0

$
43.3

$
39.4


9.9


*Beginning
in the second quarter of 2009, we are able to defer Iatan 1 carrying charges in accordance with our agreement with the MPSC that allows deferral of
certain costs until the environmental upgrades to Iatan 1 are included in our rate base.


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RATE MATTERS

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. In
addition to the information set forth below, see Note 3 of "Notes to Consolidated Financial Statements" under Item 8.

Our
rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review
and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on "rate
base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and regulatory amortization) of utility plant in service, subject to various adjustments
for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, regulatory amortization and retirement of utility plant and
write-off's as authorized by the utility commissions. In general, a request of new rates is made on the basis of a "rate base" as of a date prior to the date of the request and allowable operating
expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating
costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag between the time we incur costs and the time when we can start
recovering the costs through rates. See Note 2 of "Notes to Consolidated Financial Statements" under Item 8 for the amounts recorded for regulatory amortization.

Electric Segment

The following table sets forth information regarding electric and water rate increases since January 1, 2007:

Jurisdiction

Date
Requested

Annual
Increase
Granted

Percent
Increase
Granted

ROE

Date
EffectiveMissouri  Electric

October 1, 2007

$
22,040,395


6.70
%

10.8
%

August 23, 2008Missouri  Electric

February 1, 2006

$
29,369,397


9.96
%

10.9
%

January 1, 2007


Missouri

2009 Rate Case

On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers
in the amount of $68.2 million, or 19.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in
new generating units at Iatan 2 and the Plum Point Generating Station. We are currently in discussions about procedures to be used in this case, including the timing of the consideration and
rate recovery of our investments in the three generating facilities and other expenditures. Due to the expected in-service delay of Iatan 2, however, we do not anticipate recovering
Iatan 2 costs in this Missouri rate case. We anticipate filing a rate case at the conclusion of this case to recover the Iatan 2 costs.

2007 Rate Case

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual
increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based
on a 10.8% return on equity. The new rates went into effect August 23, 2008.

The
order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a
$5.7 million reduction to

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regulatory
amortization, which is the second component to support certain credit metrics of the overall change in revenue authorized by the MPSC. Regulatory amortization provides us additional cash
through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and
Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million annually and is
recorded as depreciation expense.

The
MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased
power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost. Off-system
sales margins are also
part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs
will be modified twice a year subject to the review and approval by the MPSC. In accordance with accounting guidance for regulated activities, 95% of the difference between the actual cost of fuel and
purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a
regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or
refunded to our customers when the fuel adjustment clause is modified. On April 1, 2009, we filed proposed rate schedules with the MPSC requesting an increase of $1.9 million in revenues
for the under recovered fuel costs recognized for the six month period ended February 28, 2009. This increase in revenue was approved by the MPSC on May 21, 2009, became effective
June 1, 2009 and is billed through our fuel adjustment clause. On October 1, 2009, we filed proposed rate schedules with the MPSC requesting a decrease of $0.8 million in revenues
for the over recovered fuel and purchased power costs recognized for the six month period ended August 31, 2009.

The
MPSC order in the rate case approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the
2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking mechanism for recovery of the costs relating to the new MPSC rules on infrastructure
inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any year we spend less than the target amount, which has been set at $8.6 million
for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset and liability amounts created using the tracking mechanism will then be netted
against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements providing for the continuation of the pension and other post-retirement
employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate orders.

The
MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed
applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective
August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff
sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

On
October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions
were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on
December 31, 2009, affirming the Commission's Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

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2006 Rate Case

All pending applications for rehearing in our Missouri 2006 rate case were denied by the MPSC on November 20, 2008. On
December 15, 2008, the OPC filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC's decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a
Petition for Writ of Review on December 19, 2008. These actions were consolidated into one proceeding. Briefs were filed by all parties and oral arguments were held on June 2, 2009. The
Cole County Circuit Court issued a ruling on December 8, 2009, affirming the MPSC's order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

On
May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the
period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a
motion to dismiss, or, in the alternative, motion for more definitive statement. On September 3, 2009, the Jasper County Circuit Court dismissed the petition with prejudice. On
October 7, 2009, the OPC appealed the Jasper County Circuit Court decision to the Missouri Court of Appeals  Southern District. The initial brief was filed by the OPC on
January 11, 2010. We filed a responsive brief on February 5, 2010.

Kansas

On November 4, 2009, we filed a request with the KCC for an annual increase in base rates for our Kansas electric customers in
the amount of $5.2 million, or 24.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury
plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. We anticipate new rates will go
into effect in July 2010.

Gas Segment

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the
amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity
of 11.3%. We have entered into a Stipulated Agreement, which was approved by the MPSC, for an increase of $2.6 million. Pursuant to the Agreement, new rates will go into effect on
April 1, 2010.

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COMPETITION

Electric Segment

SPP-RTO

Energy Imbalance Services:On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization
(RTO) launched its energy imbalance services market (EIS). In general, the SPP RTO EIS market provides real time energy for most participating members within the SPP regional footprint. Imbalance
energy prices are based on market bids and status/availability of dispatchable generation and
transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered
into the EIS market to the market participants to also serve the native load.

Day Ahead Market:The SPP and its members have been evaluating the costs and benefits on expanding the EIS market into a
full day ahead energy market with a co-optimized ancillary services market, which will include the consolidation of all SPP balancing authorities, including ours, into a single SPP
balancing authority. On April 28, 2009, the SPP Regional State Committee (SPP RSC), whose members include state commissioners from our four state commissions, and the SPP Board of Directors
(SPP BOD) endorsed a cost benefit report that recommended the SPP RTO move forward with the development of a day-ahead market with unit commitment and co-optimized ancillary
services market (Day-Ahead Market) and implement the complete Day-Ahead Market as soon as practical, which is anticipated in late 2013 or early 2014. As part of the
Day-Ahead Market, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its
members, including us, which is expected to provide operational and economic benefits for us and our customers. The implementation of the Day-Ahead Market will replace the existing EIS
market, which to date has, and is expected to continue to, provide benefits for our customers.

SPP Regional Transmission Development:On August 15, 2008, the SPP filed with the FERC proposed revisions to its
open access transmission pro forma tariff (OATT) to establish a process for including a "balanced portfolio" of economic transmission upgrades in the annual SPP Transmission Expansion Plan. The cost
of such upgrades will be recovered through a regional rate allocated to SPP members based on their load ratio share within SPP's market area of the balanced portfolio's cost. On October 16,
2008, the FERC accepted the balanced portfolio approach, which sets forth the selection process of a group of projects and regional cost allocation rules based on projected benefits and allocated
costs over a ten year period. The plan will be balanced if the portfolio is cost beneficial for each zone, including ours, within the SPP. A balanced portfolio could include projects below the 345 kv
level (which is the bright line voltage level for projects to be included in the portfolio) to increase benefits to a particular zone to achieve balance of benefits and costs over the ten year study
period. On April 28, 2009, the SPP RSC and the SPP BOD approved the first set of balanced portfolio extra high voltage transmission projects to be constructed within the SPP region. The
transmission expansion projects, totaling over $700 million, include projects in Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set of transmission expansion
projects will provide long term benefits to our customers yet expect our share of the net allocated costs to be immaterial. Also on April 28, 2009, the SPP RSC and BOD approved a new report
that recommends restructuring of the SPP's regional planning processes, which would establish an integrated planning process for reliability, transmission service and economic transmission projects,
based on a new set of planning principles that focus on the construction of a more robust transmission system large enough in both scale and geography to provide flexibility to meet SPP members' and
customers' future needs. We will actively participate in the development of these new processes as well as cost allocation and recovery issues with members, prospective customers and the state
commission representatives to the SPP RSC. On October 27, 2009, the SPP BOD endorsed a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for
new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future. The new cost allocation method will be filed at the FERC in the
second quarter of 2010. We continue to evaluate the cost and benefit impacts and our position on the new cost allocation method to determine whether it will provide
sufficient long term benefits to our customers or require modifications through the FERC approval process.

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FERC Market Power Order

On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control
area based on our failure to meet one of the FERC's wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC
issued its order accepting Empire's proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued
since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies
only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, covering over 1,000 hourly energy sales since May 16, 2005 to
numerous counterparties external to our system for wholesale sales made at market prices above the cost based prices permitted under the mitigation proposal accepted by the FERC. The refund obligation
applied to certain wholesale power sales made "inside" our service area at market based rates, even though consumption of the energy occurred outside our service area.

On
September 14, 2006, we filed a Request For Rehearing of the FERC's August 15, 2006 order regarding the refund and market power mitigation we had proposed. We requested a
rehearing and a waiver of the refund requirement in its entirety. On April 25, 2008, the FERC issued an Order that rejected our Request For Rehearing, required a Compliance Filing of our market
based rate tariff and ordered refunds with interest. We made our Compliance Filing and issued refunds totaling $340,608, including interest, on May 27, 2008. We also filed an informational
refund report with the FERC on June 26, 2008.

As
a result of the FERC's requirement for us to issue the aforementioned refunds and our belief that the FERC erred in its orders, on June 30, 2008 we initiated a Petition For
Review of the FERC's orders on our market based rate refunds in the United States Court of Appeals for the District of Columbia Circuit (DC Circuit). We requested and received approval for a
consolidation of our Petition with a similar petition by Westar Energy. On June 12, 2009, the DC Circuit denied our and Westar's Petition for FERC to review its Order requiring the refunds to
be made, concluding our efforts to recover the refunds paid.

As
part of our market based pricing authority, we are required to conduct a market power analysis within our service territory and within the SPP RTO region every three years. We filed
our triennial market power analysis with the FERC on July 30, 2009, concluding there were no material changes to our market position. As a result, we do not anticipate any changes to our
existing market based rate authority. The FERC's acceptance of our filing is pending.

Other FERC Activity

On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in
organized wholesale power markets, such as the SPP RTO in which we participate. On October 16, 2008, the FERC issued its Final Order on Wholesale Competition in Regions with Organized Electric
Markets. The Final Order will affect us as it directly affects the SPP RTO. The Final Order addresses four key areas for amending its regulations in Wholesale Competition for RTOs and Independent
System Operators (ISOs): (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market monitoring
policies; and (4) the responsiveness of RTOs and ISOs to stakeholders and customers. We continue to be involved in the SPP RTO and our state commission discussions on compliance of these new
rules.

On
May 21, 2009, the FERC issued an order clarifying that, going forward, small public utilities that have been granted waiver of Order No. 889 (Open Access Same Time
Information Systems (OASIS) requirement) and the Standards of Conduct for transmission operations, which includes us, are required to submit a notification filing if there has been a material change
in facts that may affect the basis on which a public utility's waiver was premised. The Standards of Conduct generally govern the communications

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Table of Contents

between
our day to day transmission operations personnel and our day to day wholesale marketing and sales personnel. We submitted our filing on July 13, 2009 in which we believe continuation of
our waiver, issued in 1997 and reaffirmed in 2004, is appropriate and reasonable. Based on the May 21, 2009 order, it is possible that the FERC will revoke our waiver which would impact
communication between our transmission and wholesale marketing and sales functions and operations within our organization. As part of our filing, we sought a twelve month extension in order to comply
with the Standard of Conduct requirements in the event the FERC determined that revoking our waiver was appropriate. The FERC's decision on this and other Standard of Conduct waiver filings is
pending.

Gas Segment

Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than
EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues
for distribution and other services if natural gas is purchased from another source by our eligible customers.

LIQUIDITY AND CAPITAL RESOURCES

Overview.Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial
paper
program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. As needed, we raise funds from the debt and equity capital markets, including through
our existing shelf registration statement, to fund our liquidity and capital resource needs.

Our
issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal
regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide only a
portion of the funds required in 2010 for our budgeted capital expenditures (as discussed in "Capital Requirements and Investing Activities" below). Although our working capital was negative as of
December 31, 2009, we believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with this cash provided by operating activities
will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend
payments and other cash needs through the next several years.

We
will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other
factors. See Item 1A, "Risk Factors" for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our
operating, investing and financing activities for the last three years.

Summary of Cash Flows

Fiscal Year(in millions)

2009

2008

2007Cash provided by (used in):Operating activities

$
129.6

$
93.0

$
103.5Investing activities


(154.7
)

(211.8
)

(178.9
)Financing activities


28.0


117.5


67.0Net change in cash and cash equivalents from continuing operations


2.9


(1.3
)

(8.4
)Discontinued operations








0.1Net change in cash and cash equivalents

$
2.9

$
(1.3
)
$
(8.3
)


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Cash flow from Operating Activities

We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from
operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include
depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in commodity risk management assets and liabilities and changes in the consolidated balance sheet for working
capital from the beginning to the end of the period.

Year-over-year
changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of
customer collections, payments for natural gas and coal purchases and the effects of deferred fuel recoveries. The increase in natural gas prices directly impacts the cost of gas stored in inventory.

2009 compared to 2008.In 2009, our net cash flow provided from operating activities was $129.6 million, an increase of
$36.6 million
or 39.3% from 2008. This increase was primarily a result of:



2008 compared to 2007.In 2008, our net cash flow provided from operating activities was $93.0 million, a decrease of
$10.5 million or
10% from 2007. The decrease was primarily a result of:



These
decreases were offset by higher net income and changes in levels of accounts payable.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $57.1 million from 2009 to 2008. The 2008 capital expenditures reflect
cash outlays for the December 2007 ice storm. These expenditures were incurred in 2007 but paid in the first quarter of 2008. In addition,
expenditures for new generation and distribution and transmission system additions were lower in 2009 than in 2008.

Our
net cash flows used in investing activities increased $32.8 million during 2008 as compared to 2007, primarily reflecting our construction expenditures for Plum Point Unit 1
and Iatan 2.

Our
capital costs incurred for continuing operations totaled approximately $148.8 million, $206.4 million, and $195.5 million in 2009, 2008 and 2007, respectively.

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A
breakdown of these capital costs (including AFUDC) for 2009, 2008 and 2007 is as follows:

Capital Expenditures(in millions)

2009

2008

2007Distribution and transmission system additions

$
33.7

$
46.8

$
43.5New generation  Riverton combustion turbine








3.9New generation  Plum Point Energy Station


16.3


30.9


29.8New generation  Iatan 2


66.2


82.6


44.0Storms(1)


6.4


4.3


26.9Additions and replacements  Asbury


0.3


6.0


21.7Additions and replacements  Iatan 1


13.6


32.3


14.2Additions and replacements  State Line Combined Cycle Unit, Riverton, Energy Center, State Line Unit 1 and Ozark Beach


8.9


1.9


2.1Gas segment additions and replacements


2.1


1.9


1.8Transportation


1.4


1.2


0.8Other (including retirements and salvage  net)(1)(2)


(1.4
)

(3.6
)

1.8Subtotal

$
147.5

$
204.3

$
190.5Non-regulated capital expenditures (primarily fiber optics)


1.3


2.1


5.0Subtotal capital expenditures incurred(3)

$
148.8

$
206.4

$
195.5Less capital expenditures payable(4)


(3.8
)

(6.9
)

12.1Insurance proceeds receivable


5.6





Capital lease, primarily Plum Point unit train


(2.9
)




Total cash outlay

$
155.3

$
213.3

$
183.4


(1)For
2007, storm costs of $17.8 million and Other of $1.4 million, which relate to the cost of removal, are specifically related to capital
expenditures associated with the January 2007 ice storm. $9.2 million of capitalized storm costs are related to the December 2007 ice storm.(2)Other
includes equity AFUDC of $(6.2) million, $(5.9) million and $(2.9) million for 2009, 2008 and 2007, respectively. 2009 and 2008 also include proceeds
from sale of property of $0.5 million and $1.5 million, respectively.(3)Expenditures
incurred represent the total accrued cost for work completed for the projects during the year. Discussion of capital expenditures throughout
the 10-K is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.(4)Represents
the change in unpaid capital expenditures at the end of the year and not reflected in the Investing Activities section of the Statement of Cash
Flows.


Approximately
55%, 23% and 36% of our cash requirements for capital expenditures for 2009, 2008 and 2007, respectively, were satisfied with internally generated funds. The remaining
amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

We
estimate that our capital expenditures will total approximately $110.9 million in 2010, $89.8 million in 2011 and $70.5 million in 2012 (excluding AFUDC). See
Item 1, "Business 

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Construction
Program." Of these budgeted amounts, we anticipate that we will spend the following amounts over the next three years for the following projects:

Project

2010

2011

2012Iatan 2

$
37.3

$
5.9

$
Plum Point Energy Station


3.6





Electric distribution system additions


36.0


40.1


40.1Electric transmission facilities additions


9.7


9.1


7.7Environmental upgrades  Asbury


4.4


0.1


Other


19.9


34.6


22.7Total

$
110.9

$
89.8

$
70.5


We
estimate that internally generated funds will provide approximately 64% of the funds required in 2010 for our budgeted capital expenditures. We intend to utilize a combination of
short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our equity distribution agreement discussed below, as well as
under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and our ESOP) to finance additional amounts needed beyond those provided by operating
activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. The estimates herein may be
changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons. See further discussion under
"Financing Activities" below.

Financing Activities

Our net cash flows provided by financing activities decreased $89.5 million to $28.0 million during 2009 as compared to
$117.5 million in 2008, primarily due to repayments of short-term borrowings in 2009, as well as increased cash flows from operations and lower capital expenditures.

Our
net cash flows from continuing operations provided by financing activities increased $50.4 million to $117.5 million during 2008 as compared to $67.0 million in
2007, primarily due to the issuance of first mortgage bonds and increased usage of short-term borrowings in 2008.

On
February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, as amended, we may offer and sell
shares of our common stock, par value $1.00 per share, having an aggregate offering amount of up to $120 million from time to time through UBS, as sales agent. We intend to use the net proceeds
from this equity distribution program to repay short-term debt and for general corporate purposes, including to fund our current construction program. During the fourth quarter of 2009, we
issued and sold 2,115,149 shares of our common stock, pursuant to this program, at an average price per share of $18.51, resulting in proceeds to us of approximately $37.9 million (after
payment of approximately $1.2 million in commissions to the sales agent). Since inception of the program, in the aggregate, we have issued and sold 3,767,909 shares pursuant to the program,
resulting in net proceeds to us of approximately $66.7 million. Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS.
Under the terms of the program agreement, we may also sell shares to UBS as principal for UBS' own account at a price agreed upon at the time of sale.

On
March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately
$72.6 million were used to repay short-term debt incurred, in part, to fund our current construction program.

On
May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.4 million of legal
and other financing fees, were added to our general

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funds
and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

On
December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately
$65.8 million ($69.0 million less issuance costs of $3.2 million). The proceeds were added to our general funds and used to pay down short-term indebtedness incurred,
in part, as a result of our on-going construction program.

On
March 26, 2007, we issued $80 million principal amount of first mortgage bonds. The net proceeds of approximately $79.1 million, less $0.4 million of legal
and other financing fees, were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

We
have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities,
preference stock, first mortgage bonds and trust preferred securities. As of December 31, 2009, in addition to amounts remaining under the equity distribution program described above,
$205 million remains available for issuance under this shelf registration statement. Of the original $400 million, $250 million was available for first mortgage bonds with
$175 million remaining available after the issuance of $75 million in first mortgage bonds on March 27, 2009. We plan to use a portion of the proceeds from issuances under this
shelf to fund a portion of the capital expenditures for our new generation projects.

On
July 15, 2005, we entered into a $150 million unsecured revolving credit facility which was scheduled to terminate on July 15, 2010. On March 14, 2006, we
entered into the First Amended and Restated Unsecured Credit Agreement which amended and restated the $150 million unsecured revolving credit facility. The principal amount of the credit
facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy
Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was
$8.5 million as of February 1, 2010. On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated this facility
again. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the pricing and fees under the facility were
amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank's prime commercial rate, (B) the federal funds
effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our
current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility increased from 0.80% to 2.70%. A
facility fee is payable quarterly on the full amount of the commitments under the facility and a usage fee is payable on the full amount of the commitments under the facility for any period in which
we have drawn less than 33% of the total revolving commitments under the facility, in each case based on our current credit ratings. In addition, upon entering into the amended and restated facility,
we paid an upfront fee to the revolving credit banks of $900,000 in the aggregate. The aggregate amount of the revolving commitments remained unchanged at $150 million and there were no other
material changes to the terms of the facility. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our
total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as
net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing
four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds
thereunder. As of December 31, 2009, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the
aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our

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cash
in the normal course of operations. There was $32.0 million of outstanding borrowings under this agreement at December 31, 2009 and an additional $18.5 million was used to
back up our outstanding commercial paper.

On
March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for
working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has
substantially identical covenants and terms as (other than pricing), our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010 discussed above. There were no borrowings
under this agreement at December 31, 2009.

The
principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all
of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture
could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months
within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective
issue of new first mortgage bonds. Our earnings for the year ended December 31, 2009 would permit us to issue approximately $239.9 million of new first mortgage bonds based on this test
with an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of
net property additions. At December 31, 2009, we had retired bonds and net property additions which would enable the issuance of at least $644.8 million principal amount of bonds if the
annual interest requirements are met. As of December 31, 2009, we are in compliance with all restrictive covenants of the EDE Mortgage.

The
principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially
all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be
issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a
limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after
giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for
the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2009, these tests would not allow us to issue new first mortgage bonds.

Currently,
our corporate credit ratings and the ratings for our securities are as follows:

Fitch

Moody's

Standard & Poor'sCorporate Credit Rating

n/r*

Baa2

BBB-First Mortgage Bonds

BBB+

Baa1

BBB+Senior Notes

BBB

Baa2

BBB-Trust Preferred Securities

BB+

Baa3

BBCommercial Paper

F2

P-2

A-3Outlook

Negative

Negative

Stable


*Not
rated.


On
November 5, 2008, Standard & Poor's raised our senior unsecured debt rating from BB+ (a non-investment grade rating) to BBB- as a result of a
reevaluation of the application of their notching

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criteria
for U. S. investment-grade investor-owned utility operating company unsecured debt to better reflect the relatively strong recovery prospects of creditors in this sector. As a result, the
senior unsecured debt of most utilities will now be rated the same as the corporate credit rating almost uniformly, even when a considerable amount of secured debt is outstanding.

On
February 14, 2008, Moody's placed all of our ratings on review for possible downgrade. Moody's announced that the review would consider the cumulative impact that certain
negative events, including severe weather and operational disruptions in 2007 and 2008, have had on our cash flow and overall financial flexibility at the current rating level as well as consider the
potential for elevated costs related to our capital spending plan in 2008. On May 12, 2008, Moody's affirmed our ratings with a negative outlook.

On
January 25, 2008, Fitch affirmed our ratings but revised their rating outlook to negative. At the time of the change, the negative rating outlook reflected uncertainty
surrounding the outcome of our Missouri rate filing and weakness in our projected financial measures relative to Fitch guidelines. Events leading to the revision were storm damage incurred in December
2007 and the extended Asbury coal plant outage we experienced last winter. On January 22, 2010, Fitch Ratings downgraded our trust preferred securities from BBB- to BB+ as a result
of Fitch's recently revised guidelines for rating preferred stock and hybrid securities issued by companies in all sectors. The new guidelines typically resulted in downgrades of one notch for many
deferrable instruments that are currently performing. The new guidelines also provide guidance on how Fitch will rate and notch hybrids and preferred securities at different stages in the"life cycle"
of an instrument. All of the affected instruments are performing and were downgraded by a single notch; Fitch does not currently have reason to expect that deferral or loss absorption will be
activated.

A
security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each
security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

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CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of December 31, 2009. Not included in these amounts
are expected obligations associated with our share of the Iatan 2 construction and Iatan 1 environmental construction additions for which we have not yet been billed. Other pension and postretirement
benefit plans are funded on an ongoing basis to match their corresponding costs, per regulatory requirements and have been estimated for 2010-2014 as noted below.

Payments Due By Period
(in millions)Contractual Obligations(1)

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 YearsLong-term debt (w/o discount)

$
639.0

$
50.6

$
1.3


111.6

$
475.5Note payable to securitization trust


50.0











50.0Interest on long-term debt


669.8


41.2


80.7


73.0


474.9Short-term debt


50.5


50.5








Capital lease obligations


4.6


0.7


0.6


0.6


2.7Operating lease obligations(2)


8.2


1.2


1.9


1.7


3.4Electric purchase obligations(3)


275.9


72.5


85.4


51.5


66.5Gas purchase obligations(4)


60.6


11.6


15.2


13.9


19.9Open purchase orders


33.2


33.1


0.1





Plum Point


3.6


3.6








Postretirement benefit obligation funding


17.9


3.4


7.3


7.2


Pension benefit funding


57.5


12.0


21.6


23.9


Other long-term liabilities(5)


3.7


0.1


0.3


0.3


3.0TOTAL CONTRACTUAL OBLIGATIONS(6)

$
1,874.5

$
280.5

$
214.4

$
283.7

$
1,095.9


(1)Some
of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.(2)Excludes
payments under our Elk River Wind Farm, LLC and Cloud County Wind Farm, LLC agreements, as payments are contingent upon output of the
facilities. Payments under the Elk River Wind Farm, LLC agreement can run from zero up to a maximum of approximately $16.9 million per year based on a 20 year average cost and an
annual output of 550,000 megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a maximum of approximately $14.6 million per year based on a
20-year average cost.(3)Includes
a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power
for 2010 through 2015 for Plum Point.(4)Represents
fuel contracts and associated transportation costs of our gas segment.(5)Other
long-term liabilities primarily represent electric facilities charges owed to City Utilities of Springfield, Missouri of $11,000 per month
over 30 years.(6)Our
estimate of uncertain tax liabilities totaled $0.9 million at December 31, 2009. Due to the uncertainties surrounding this estimate, we
cannot reasonably estimate the timing of potential payments, if any, and have not included any in the table above.


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DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally
available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after
considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of December 31, 2009, our retained
earnings balance was $10.1 million, compared to $13.6 million as of December 31, 2008, after paying out $44.8 million in dividends during 2009. A reduction of our dividend
per share, partially or in whole, could have an adverse effect on our common stock price. On February 4, 2010, the Board of Directors declared a quarterly dividend of $0.32 per share on common
stock payable March 15, 2010 to holders of record as of March 1, 2010.

Our
diluted earnings per share were $1.18 for the year ended December 31, 2009 and were $1.17 and $1.09 for the years ended December 31, 2008 and 2007, respectively.
Dividends paid per share were $1.28 for the year ended December 31, 2009 and for each of the years ended December 31, 2008 and 2007.

Under
Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which
the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax.
However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the
Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the
FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive
analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial
condition of the utility.

In
addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may
not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock
financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would
exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another
corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to
our shareholders by increasing the basket
available to pay dividends by $10.75 million, as described above. As of December 31, 2009, this restriction did not prevent us from issuing dividends.

In
addition, under certain circumstances, our Junior Subordinated Debentures, 81/2% Series due 2031, reflected as a note payable to securitization trust on our balance
sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if:
(1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable
steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred
interest payments on the Junior Subordinated Debentures, 81/2% Series due 2031 or given notice of a deferral of interest payments. As of December 31, 2009, there were no such
restrictions on our ability to pay dividends.

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OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the
normal course of business.

CRITICAL ACCOUNTING POLICIES

Set forth below are certain accounting policies that are considered by management to be critical and that typically require difficult,
subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that
could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on
future financial results.

Pensions and Other Postretirement Benefits (OPEB).We recognize expense related to pension and postretirement benefits as earned
during the
employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our pension and OPEB expense or
benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement
date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits (effective January 1, 2005) and OPEB benefits (effective
January 1, 2007) unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years.

In
our 2005 electric Missouri Rate Case the MPSC ruled that we would be allowed to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate order,
we prospectively calculated the value of plan assets using a market related value method as allowed by the Accounting Standard Codification (ASC) guidance on defined benefit plans disclosure.

The
MPSC ruling also allowed us to record the Missouri portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. Therefore, the
deferral of these costs began in the second quarter of 2005. In our 2006 Kansas Rate Case, the KCC also ruled that we would be allowed to change our recognition of pension costs, deferring the Kansas
portion of any costs above or below the amount included in our rate case as a regulatory asset or liability. In our agreement with the MPSC regarding the purchase of Missouri Gas by EDG, we were
allowed to adopt this pension cost recovery methodology for EDG, as well. Also, it was agreed that the effects of purchase accounting entries related to pension and other post-retirement
benefits would be recoverable in future rate proceedings. Thus the fair value adjustment acquisition entries have been recorded as regulatory assets, as we believe these amounts are probable of
recovery in future rates. The regulatory asset will be reduced by an amount equal to the difference between the regulatory costs and the estimated GAAP costs. The difference between this total and the
costs being recovered from customers will be deferred as a regulatory asset or liability in accordance with the ASC guidance on regulated operations, and recovered over a period of 5 years. We
now expect future pension expense or benefits are probable of full recovery in rates charged to our Missouri and Kansas customers, thus lowering our sensitivity to accounting risks and uncertainties.

Our
2006 Missouri rate case order allows us to defer any OPEB cost that is different from those allowed recovery in this rate case. This treatment is similar to treatment afforded
pension costs in our March 2005 rate case. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into expense over ten years and the recognition
of regulatory assets and liabilities as described in the immediately preceding paragraph.

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On
December 31, 2006, we adopted the ASC guidance on defined benefit plans disclosure which requires an employer to recognize the overfunded or underfunded status of a defined
benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the
changes occur through comprehensive income of a business entity. We adopted the guidance for the fiscal year ended December 31, 2006. Based on the regulatory treatment of pension and OPEB
recovery afforded in our jurisdictions, we have concluded that the amount of unfunded defined benefit pension and postretirement plan obligations will be recorded as regulatory assets on our balance
sheet rather than as reductions of equity through comprehensive income.

Our
2008 Missouri rate case order approved Stipulations providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism
established in our 2006 and 2007 Missouri rate cases. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of pension and postretirement benefits. We expect to
be required to fund approximately $12.0 million to our pension plan and $3.2 million for OPEB benefits in 2010. (See Note 8 of "Notes to Consolidated Financial Statements" under
Item 8).

Risks
and uncertainties affecting the application of our pension accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations
(i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Factors that could result in additional pension expense and/or
funding include: a lower discount rate than estimated, higher compensation rate increases, lower return on plan assets, and longer retirement periods.

Risks
and uncertainties affecting the application of our OPEB accounting policy and related funding include: future rate of return on plan assets, interest rates used in valuing benefit
obligations (i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates). See Note 1 and
Note 8 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

Hedging Activities.We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas
prices. We enter into
contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an
attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual
obligations, actual results could differ materially from intended results. All derivative instruments are recognized at fair value on the balance sheet with gains and losses from effective instruments
deferred in other comprehensive income (in stockholders' equity) or a regulatory asset or liability for instruments entered into after September 1, 2008, while gains and losses from ineffective
(overhedged) instruments are recognized as the fair value of the derivative instrument changes. With the addition of the Missouri fuel adjustment mechanism effective September 1, 2008, we now
have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs on our net income.

Risks
and uncertainties affecting the application of this accounting policy include: market conditions in the energy industry, especially the effects of price volatility, regulatory and
global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item,
estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized
immediately in our Consolidated Statement of Income and then deferred to a regulatory asset or liability, given it is probable of recovery through our fuel adjustment mechanism. See Note 14 of
"Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our hedging information.

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As
of February 5, 2010, approximately 77% of our anticipated volume of natural gas usage for our electric operations for the year 2010 is hedged, either through physical or
financial contracts, at an average price of $6.322 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations
for the next three years are hedged at the following average prices per Dth:

Year

% Hedged

Dth Hedged

Average Price2011


71
%

5,115,000

$
5.8402012


40
%

3,085,000

$
7.0162013


17
%

1,200,000

$
7.295


We
attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months,
(2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. As of February 5, 2010, we have 91% of our expected remaining winter heating season
usage (through March 2010) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is $3.948 per Dth. We target to have 95% of
our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of February 7, 2010, we
had 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 33% of our storage capacity. We have an additional 0.6 million Dths hedged through
financial derivatives and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of
second year and up to 20% of third year expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A PGA clause is included in our rates for our gas segment
operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability
account on our balance sheet.

Regulatory Assets and Liabilities.In accordance with the ASC accounting guidance for regulated activities, our financial
statements reflect
ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (Missouri, Kansas, Arkansas, Oklahoma and FERC).

In
accordance with accounting guidance for regulated activities, we record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance
with the accounting guidance, which requires that an asset be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate
making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. Additionally, we follow the accounting guidance for regulated
activities which says that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred
costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators.

Historically,
all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking
procedures. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no
longer probable that such amounts will be recovered through future revenues. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric
competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC accounting guidance for regulated activities with respect to
continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of ASC accounting guidance for regulated
activities based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material
adverse effect on our financial condition and results of operations.

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As
of December 31, 2009, we have recorded $169.0 million in regulatory assets and $87.5 million as regulatory liabilities. See Note 3 of "Notes to
Consolidated Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

Risks
and uncertainties affecting the application of this accounting policy include: regulatory environment, external regulatory decisions and requirements, anticipated future regulatory
decisions and their impact of deregulation and competition on ratemaking process, unexpected disallowances, possible changes in accounting standards and the ability to recover costs.

Unbilled Revenue.At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy and
natural gas that has
been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage, estimating the impact of weather and
other factors that affect usage (such as line losses) for the unbilled period and estimating loss of energy during transmission and delivery.

Contingent Liabilities.We are a party to various claims and legal proceedings arising in the ordinary course of our business,
which are primarily
related to workers' compensation and public liability. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our
evaluation as of the end of 2009, we believe that we have accrued liabilities in accordance with ASC accounting guidance sufficient to meet potential liabilities that could result from these claims.
This liability at December 31, 2009 and 2008 was $3.1 million and $3.5 million, respectively.

Risks
and uncertainties affecting these assumptions include: changes in estimates on potential outcomes of litigation and potential litigation yet unidentified in which we might be named
as a defendant.

Goodwill.As of December 31, 2009, the consolidated balance sheet included $39.5 million of goodwill. All of this
goodwill was derived
from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual
basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market and
income approaches is used to estimate the fair value of goodwill.

We
use the market approach which estimates fair value of the gas reporting unit by comparing certain financial metrics to comparable companies. Comparable companies whose securities are
actively traded in the public market are judgmentally selected by management based on operational and economic similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and
amortization) multiples of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an estimate of fair value.

We
also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and
performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted
cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A key qualitative assumption
considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas reporting unit. Some of the key quantitative assumptions included in our tests
involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. We believe it is unlikely that a change to one of these key
assumptions, by itself, would be sufficient to impact the estimated fair value determined in our discounted cash flow calculation enough to result in an impairment charge. However, if significant
negative changes occurred to multiple key assumptions, an impairment charge could result. With the exception of the capital spending rate, the key assumptions noted are significantly determined by
market factors and significant changes in market factors that impact the gas

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reporting
unit would likely be mitigated by our current and future regulatory rate design to some extent. Other risks and uncertainties affecting these assumptions include: management's identification
of impairment indicators, changes in business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a recent decline in gas customer growth and
demand, but this was anticipated in our assumptions for purposes of the discounted cash flow calculation. Our forecasts anticipate the customer contraction will minimize in the near future and return
to positive customer growth within the next few years.

We
weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of November 30, 2009
indicated the estimated fair market value of the gas reporting unit to be 10-15% higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were
reasonable, significant adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings.

Use of Management's Estimates.The preparation of our consolidated financial statements in conformity with generally accepted
accounting principles
(GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those
related to unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment and goodwill evaluations, employee benefit obligations, contingent liabilities, asset
retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Recently Issued and Proposed Accounting Standards under Note 1 of "Notes to Consolidated Financial Statements" under
Item 8.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price
risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by
a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

Market Risk and Hedging Activities.Prices in the wholesale power markets often are extremely volatile. This volatility impacts
our cost of power
purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are
not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

We
engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which
typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk and to help manage
our exposure resulting from purchasing most of our natural gas on the volatile spot market for the
generation of power for our native-load customers. See Note 14 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

Commodity Price Risk.We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas,
and electricity
and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We
satisfied 69.8% of our 2009 generation fuel supply need through coal. Approximately 88% of our 2009 coal supply was Western coal. We have contracts to supply a portion of the fuel for
our coal plants through 2013. These contracts satisfy approximately 98% of our anticipated fuel requirements for 2010, 59% for 2011, 28% for 2012 and 30% for our 2013 requirements for our Asbury and
Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We
are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs
to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with
respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of February 5,
2010, 77%, or 6.5 million Dths's, of our anticipated volume of natural gas usage for our electric operations for 2010 is hedged. See Note 14 of "Notes to Consolidated Financial
Statements" under Item 8 for further information.

Based
on our expected natural gas purchases for our electric operations for 2010, if average natural gas prices should increase 10% more in 2010 than the price at December 31,
2009, our natural gas expenditures would increase by approximately $1.0 million based on our December 31, 2009 total hedged positions for the next twelve months. However, such an
increase would be probable of recovery through fuel adjustment mechanisms. With the addition of the Missouri fuel adjustment mechanism effective September 1, 2008, we now have a fuel cost
recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

We
attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of
February 7, 2010, we have 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 33% of our storage capacity. We have an additional
0.6 million Dths hedged through financial derivatives and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a

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minimum
of 50% of the current year, up to 50% of the second year and up to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, due to purchased
natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Credit Risk.In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial
condition and
the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 14 of "Notes to Consolidated Financial Statements (Unaudited)"
regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding
agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is
typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding
agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with various trading counterparties that
resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets and margin deposit liabilities at
December 31, 2009 and December 31, 2008:

(in millions)

2009

2008Margin deposit assets

$
2.9

$
10.7


Our
exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may
involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at December 31, 2009, reflecting that our counterparties are exposed
to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

(in millions)Net unrealized mark-to-market losses for physical forward natural gas contracts

$
8.4Net unrealized mark-to-market gains for financial natural gas contracts


(0.4
)Net credit exposure

$
8.0


The
$0.4 million net unrealized mark-to-market gain for financial natural gas contracts is comprised of $4.3 million of exposure to counterparties
of Empire for unrealized losses and $4.7 million of exposure to Empire of unrealized gains, of which $4.5 million is from a single counterparty. We are holding no collateral from this
counterparty since we are below the $10 million mark-to-market collateral threshold in our agreement with this counterparty. As noted above, we have $2.9 million
on deposit for NYMEX counterparty exposure to Empire, of which $2.4 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their December 31, 2009 levels, our
collateral requirement would increase $2.4 million. If these prices increased 25%, our collateral requirement would decrease $3.4 million and our counterparties would be required to post
$0.5 million in collateral with Empire.

We
sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk
associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for
purchases of energy-related commodities, including natural gas in our fuel procurement process.

Interest Rate Risk.We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and
other
short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit

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agreement)
to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 6 and 7 of "Notes to Consolidated
Financial Statements" under Item 8 for further information.

If
market interest rates average 1% more in 2010 than in 2009, our interest expense would increase, and income before taxes would decrease by less than $0.3 million. This amount
has been determined by considering the impact of the hypothetical interest rates on our highest month-end
commercial paper balance for 2009. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant
change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their
possible effects, the sensitivity analysis assumes no changes in our financial structure.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To
the Board of Directors and Stockholders
of the Empire District Electric Company:

In
our opinion, the consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of The Empire
District Electric Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index
appearing under Item 15 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control  Integrated
Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The
Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on
these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the
risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 19, 2010

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED BALANCE SHEETS

December 31,2009

2008($-000's)AssetsPlant and property, at original cost:Electric

$
1,619,949

$
1,490,829Natural gas


58,180


56,282Water


10,891


10,560Other


29,564


28,481Construction work in progress


302,012


289,4602,020,596


1,875,612Accumulated depreciation and amortization


561,586


527,2451,459,010


1,348,367Current assets:Cash and cash equivalents


5,620


2,754Accounts receivable  trade, net of allowance of $1,087 and $1,265, respectively


36,136


39,487Accrued unbilled revenues


23,717


25,170Accounts receivable  other


21,417


19,353Fuel, material and supplies


43,973


48,608Unrealized gain in fair value of derivative contracts


2,782


2,395Prepaid expenses and other


4,438


5,675Regulatory assets


772


2,033138,855


145,475Noncurrent assets and deferred charges:Regulatory assets


168,254


162,026Goodwill


39,492


39,492Unamortized debt issuance costs


10,638


9,133Unrealized gain in fair value of derivative contracts


2,525


6,434Deferred investment tax credits


17,713


Other


3,359


2,919241,981


220,004Total assets

$
1,839,846

$
1,713,846


(Continued)

The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

December 31,2009

2008($-000's)Capitalization and liabilitiesCommon stock, $1 par value, 100,000,000 shares authorized, 38,112,280 and 33,981,579 shares issued and outstanding,
respectively

$
38,112

$
33,982Capital in excess of par value


551,631


483,443Retained earnings


10,068


13,579Accumulated comprehensive income/(loss), net of income taxes


339


(2,132
)Total common stockholders' equity


600,150


528,872Long-term debt (net of current portion)Note payable to securitization trust


50,000


50,000Obligations under capital lease


2,563


174First mortgage bonds and secured debt


339,643


312,953Unsecured debt


247,950


248,440Total long-term debt


640,156


611,567Total long-term debt and common stockholders' equity


1,240,306


1,140,439Current liabilities:Accounts payable and accrued liabilities


67,406


69,502Current maturities of long-term debt


51,021


20,160Short-term debt


50,500


102,000Customer deposits


10,394


9,577Interest accrued


5,698


5,921Fair value of derivative contracts


4,337


12,276Taxes accrued


3,386


3,174192,742


222,610Commitments and contingencies (Note 11)Noncurrent liabilities and deferred credits:Regulatory liabilities


87,533


66,585Deferred income taxes


194,315


173,511Unamortized investment tax credits


20,125


2,917Pension and other postretirement benefit obligations


84,240


83,151Fair value of derivative contracts


426


3,302Other


20,159


21,331406,798


350,797Total capitalization and liabilities

$
1,839,846

$
1,713,846


The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31,2009

2008

2007($-000's, except per share amounts)Operating revenues:Electric

$
433,133

$
446,466

$
425,161Gas


57,314


65,438


59,877Water


1,764


1,782


1,879Other


4,957


4,477


3,243497,168


518,163


490,160Operating revenue deductions:Fuel and purchased power


182,028


204,058


191,230Cost of natural gas sold and transported


35,601


42,630


37,626Regulated operating expenses


73,086


71,918


71,367Other operating expenses


1,801


1,889


1,611Maintenance and repairs


33,012


28,549


32,059Gain on sale of assets








(1,241
)Depreciation and amortization


51,494


53,562


52,599Provision for income taxes


19,571


19,128


14,416Other taxes


26,080


25,417


24,927422,673


447,151


424,594Operating income


74,495


71,012


65,566Other income and (deductions):Allowance for equity funds used during construction


6,209


5,929


2,923Interest income


217


1,057


326Benefit/(provision) for other income taxes


(311
)

2


(28
)Other  non-operating expense, net


(460
)

(1,569
)

(969
)5,655


5,419


2,252Interest charges:Long-term debt


42,084


36,041


31,120Note payable to securitization trust


4,250


4,250


4,250Short-term debt


1,125


1,854


2,940Allowance for borrowed funds used during construction


(7,924
)

(6,589
)

(4,742
)Other


(681
)

1,153


1,06938,854


36,709


34,637Income from continuing operations


41,296


39,722


33,181Income from discontinued operations, net of tax








63Net income

$
41,296

$
39,722

$
33,244Weighted average number of common shares outstanding  basic


34,924


33,821


30,587Weighted average number of common shares outstanding  diluted


34,956


33,860


30,610Earnings from continuing operations per weighted average share of common stock  basic and diluted

$
1.18

$
1.17

$
1.09Earnings from discontinued operations per weighted average share of common stock  basic and diluted








0.00Total earnings per weighted average share of common stock  basic and diluted

$
1.18

$
1.17

$
1.09Dividends declared per share of common stock

$
1.28

$
1.28

$
1.28


The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31,2009

2008

2007($-000's)Net income

$
41,296

$
39,722

$
33,244Reclassification adjustments for (gain)/loss included in net income or reclassified to regulatory asset or liability


13,568


(3,872
)

(1,610
)Net change in fair market value of open derivative contracts for period


(9,576
)

(17,394
)

5,229Income taxes


(1,521
)

8,102


(1,379
)Comprehensive income

$
43,767

$
26,558

$
35,484


The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

Common
Stock

Capital in
excess of Par

Retained
earnings

Accumulated
comprehensive
Income/(loss)

Total($-000's)Balance at December 31, 2006

$
30,251

$
406,650

$
22,916

$
8,792

$
468,609Net income








33,244





33,244Stock/stock units issued through:Public offering


3,000


62,779








65,779Stock purchase and reinvestment plans


355


7,956








8,311Dividends declared








(38,953
)




(38,953
)Cumulative effect of adopting a change in accounting








(54
)




(54
)Reclassification adjustment for gains included in net income











(1,610
)

(1,610
)Change in fair value of open derivative contracts for period











5,229


5,229Income taxes











(1,379
)

(1,379
)Balance at December 31, 2007


33,606


477,385


17,153


11,032


539,176Net income








39,722





39,722Stock/stock units issued through:Stock purchase and reinvestment plans


376


6,058








6,434Dividends declared








(43,296
)




(43,296
)Reclassification adjustment for gains included in net income











(3,872
)

(3,872
)Change in fair value of open derivative contracts for period











(17,394
)

(17,394
)Income taxes











8,102


8,102Balance at December 31, 2008


33,982


483,443


13,579


(2,132
)

528,872Net income








41,296





41,296Stock/stock units issued through:Public offering


3,664


60,825








64,489Stock purchase and reinvestment plans


466


7,363








7,829Dividends declared








(44,807
)




(44,807
)Reclassification adjustment for losses included in net income











13,568


13,568Change in fair value of open derivative contracts for period











(9,576
)

(9,576
)Income taxes











(1,521
)

(1,521
)Balance at December 31, 2009

$
38,112

$
551,631

$
10,068

$
339

$
600,150


The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,2009

2008

2007($-000's)Operating activities:Net income

$
41,296

$
39,722

$
33,244Adjustments to reconcile net income to cash flows from operating activities:Depreciation and amortization


62,247


59,066


57,317Pension and other postretirement benefit costs


4,096


8,282


9,490Deferred income taxes and unamortized investment tax credit, net


15,324


8,580


18,681Allowance for equity funds used during construction


(6,209
)

(5,929
)

(2,923
)Stock compensation expense


2,616


2,169


2,394Non cash (gain)/loss on derivatives


10,350


(39
)

(893
)Gain on the sale of assets


(457
)




(1,402
)Impairment of other non-operating investment





556


Cash flows impacted by changes in:Accounts receivable and accrued unbilled revenues


2,989


(10,938
)

(10,216
)Fuel, materials and supplies


4,635


(4,720
)

(2,869
)Prepaid expenses, other current assets and deferred charges


(7,464
)

(2,683
)

(13,057
)Accounts payable and accrued liabilities


(1,305
)

(4,905
)

11,970Interest, taxes accrued and customer deposits


806


2,234


2,532Other liabilities and other deferred credits


699


1,597


(811
)Net cash provided by operating activities of continuing operations


129,623


92,992


103,457Net cash provided by operating activities of discontinued operations








208Total net cash provided by operating activities


129,623


92,992


103,665


(Continued)

The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

Year Ended December 31,2009

2008

2007($-000's)Investing activities:Capital expenditures  regulated

$
(154,016
)
$
(211,311
)
$
(178,469
)Capital expenditures and other investments  non-regulated


(1,239
)

(1,969
)

(4,924
)Proceeds from the sale of property, plant and equipment


544


1,538


1,250Proceeds from the sale of other segment businesses








3,240Net cash used in investing activities of continuing operations


(154,711
)

(211,742
)

(178,903
)Net cash used in investing activities of discontinued operations








(12
)Total net cash used in investing activities


(154,711
)

(211,742
)

(178,915
)Financing activities:Proceeds from first mortgage bonds  electric


75,000


89,950


79,831Proceeds from issuance of common stock, net of issuance costs


70,271


5,385


71,721Long-term debt issuance costs


(2,397
)

(3,168
)

(1,078
)Net short-term borrowings (repayments)


(51,500
)

68,960


(44,010
)Repayment of first mortgage bonds


(20,025
)




Dividends


(44,807
)

(43,296
)

(38,953
)Proceeds from issuance of notes payable


2,470





Other


(1,058
)

(370
)

(452
)Net cash provided by financing activities of continuing operations


27,954


117,461


67,059Net cash used in financing activities of discontinued operations








(69
)Net cash provided by financing activities


27,954


117,461


66,990Net decrease in cash and cash equivalents


2,866


(1,289
)

(8,260
)Cash and cash equivalents, beginning of year


2,754


4,043


12,303Cash and cash equivalents, end of year

$
5,620

$
2,754

$
4,0432009

2008

2007Supplemental cash flow information:Interest paid

$
45,730

$
40,384

$
35,884Income taxes paid (received), net of refund


3,246


8,706


(1,211
)Supplementary non-cash investing activities:Change in accrued additions to property, plant and equipment not reported above

$
(3,833
)
$
(6,895
)
$
12,175Capital lease obligations for purchase of new equipment


2,946








The
accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Summary of Significant Accounting Policies

General

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation
organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part
of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary engaged in the distribution of natural gas in
Missouri. It provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment consists of a 100% interest in Empire District Industries Inc
(EDI), which holds our fiber optics business. See Note 12. In 2009, 87.5% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of
water), 11.5% from sales from our gas segment and 1.0% from our other segment.

The
utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the
Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the
ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.

Our
electric revenues in 2009 were derived as follows: residential 41.6%, commercial 31.4%, industrial 15.2%, wholesale on-system 4.2%, wholesale off-system 3.3%,
miscellaneous sources, primarily public authorities, 2.7% and other electric revenues 1.6%. Our retail electric revenues for 2009 by jurisdiction were as follows: Missouri 89.1%, Kansas 5.1%, Arkansas
2.8%, and Oklahoma 3.0%.

Our
gas operations serve approximately 45,000 customers and the 2009 gas operating revenues were derived as follows: residential 63.1%, commercial 27.1%, industrial 3.6%, and other 6.2%.

Basis of Presentation

The consolidated financial statements include the accounts of EDE, EDG, and EDI. The consolidated entity is referred to throughout as
"we" or the "Company". Significant intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain
immaterial reclassifications have been made to prior year information to conform to the current year presentation. Subsequent events were evaluated through February 19, 2010, the date these
financial statements were issued.

Discontinued Operations

In September 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting
purposes, this business has been classified as discontinued operations and is not included in our segment information.

Accounting for the Effects of Regulation

In accordance with in accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial
statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and
the FERC).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We
record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with the ASC guidance for regulated operations which say that an
asset should be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate making purposes and the current available
evidence indicates that future revenue will be provided to permit recovery of the cost. This guidance also says that a liability should be recorded when a regulator has provided current recovery for a
cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the
orders of our regulators.

Historically,
all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking
procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no
longer probable that such amounts will be recovered through future revenues. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric
competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued
recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may
also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results
of operations. (See Note 3 for further discussion of regulatory assets and liabilities).

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect
the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectibility
of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of
stock based compensation, tax provisions and derivatives. Actual amounts could differ from those estimates.

Revenue Recognition

For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last
bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet
billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer
classes. We recorded estimated unbilled revenue of $23.7 million and $25.2 million as of December 31, 2009 and 2008, respectively.

Municipal Franchise Taxes

Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other
taxes in the Consolidated Statements of Income. Municipal franchise taxes of $10.2 million, $10.2 million and $10.0 million were recorded for each of the years ended
December 31, 2009, 2008 and 2007, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Property, Plant & Equipment

The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material
and an allocation of general and administrative costs, plus an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are
charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. In 2007, we
recognized a $1.2 million pre-tax gain from the sale of our unit train. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A
liability is created for any additions to electric or gas utility property that is paid for by advances from developers. For a period of five years the Company refunds, to the developer, a pro rata
amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant
in service. The liability as of December 31, 2009 and 2008 was $9.7 million and $10.5 million, respectively.

As
of December 31, 2009 and 2008, we had recorded accrued cost of removal of $49.8 million and $40.1 million, respectively, for our electric operating segment. This
represents an estimated cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. From January 2002 through March 2005, we suspended accruing the
cost of removing plant from service upon retirement through depreciation rates pursuant to our 2001 Missouri rate case. Pursuant
to our 2005 Missouri rate order, we again began accruing cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets) on April 1,
2005. These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We reclassify the accrued cost of dismantling and
removing plant from service upon retirement from accumulated depreciation to a regulatory liability.

We
have a similar cost of removal regulatory liability for our gas operating segment. This amount at December 31, 2009 and 2008 was $3.3 million and $3.6 million,
respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the
period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to
adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset.
Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

We
have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12%
ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant along with a liability for future asset retirement obligations associated with the removal of
asbestos located at the Riverton and Asbury Plants. In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and
substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of
these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up
to the estimated settlement date.

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All
of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted
risk-free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could
occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements.

The
balances at the end of 2008 and 2009 are shown below.

(000's)

Liability
Balance
12/31/08

Liabilities
Recognized

Liabilities
Settled

Accretion

Cash Flow
Revisions

Liability
Balance at
12/31/09Asset Retirement Obligation

$
3,468

$


$


$
139

$


$
3,607




(000's)

Liability
Balance
12/31/07

Liabilities
Recognized

Liabilities
Settled

Accretion

Cash Flow
Revisions

Liability
Balance at 12/31/08Asset Retirement Obligation

$
3,333

$


$


$
135

$


$
3,468


Upon
adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a non-recurring discounted liability and a
regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and
depreciation expense as a regulatory asset. At December 31, 2009 and 2008, our regulatory assets relating to asset retirement obligations totaled $3.3 million and $3.1 million,
respectively.

Also
as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an
asset retirement obligation under this guidance, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.

Depreciation

Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by
regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other businesses are computed at
straight-line rates over the estimated useful life of the properties. (See Note 2 for additional details regarding depreciation rates).

In
accordance with our 2006 and 2008 rate orders from the MPSC, we recorded approximately $4.5 million and $8.2 million of regulatory amortization during 2009 and 2008,
respectively. This amortization included in our rates was granted in the Experimental Regulatory Plan approved by the MPSC on August 2, 2005. It provides additional cash flow to enhance the
financial support for our current generation expansion plan. It is related to our investment in Iatan 2 and also includes our Riverton V84.3A2 combustion turbine (Riverton Unit 12) and
environmental improvement and upgrades at Asbury and Iatan 1. This amortization is included as depreciation and amortization expense and in accumulated depreciation and amortization on the
consolidated balance sheet.

Allowance for Funds Used During Construction

As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for
funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to
our construction program are capitalized as a cost of construction. This accounting

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

practice
offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

AFUDC
does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are
permitted as a component of rate base and the provision for depreciation.

In
accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 7.0% for 2009, 7.8% for 2008 and 7.7% for 2007, compounded
semiannually, in determining AFUDC for all of our projects except Iatan 2. The specific Iatan 2 AFUDC rate is a result of our Experimental Regulatory Plan approved by the MPSC on August 2,
2005. In this agreement, we were allowed to receive the regulatory amortization discussed above, in rates prior to the completion of Iatan 2. As a result, the equity portion of our AFUDC rate for the
Iatan 2 project was reduced by 2.5 percentage points. (See Note 3 for additional discussion of our regulatory plan.)

Accounts Receivable

Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear
interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account
balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. The allowance for doubtful accounts at December 31, 2009 and 2008
was $1.1 million and $1.3 million, respectively.

Asset Impairments

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on several criteria, including but not limited to revenue trends, undiscounted
forecasted cash flows and other operating factors, to determine the impairment amount. None of our assets were impaired as of December 31, 2009 and 2008.

Goodwill

As of December 31, 2009, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was
derived from our gas acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an
annual basis or whenever events or circumstances indicate possible impairment. Absent an indication of fair value from a potential buyer or a similar specific transaction, a combination of the market
and income approaches is used to estimate the fair value of goodwill.

We
use the market approach which estimates fair value of the gas reporting unit by comparing certain financial metrics to comparable companies. Comparable companies whose securities are
actively traded in the public market are judgmentally selected by management based on operational and economic similarities. We utilize EBITDA (earnings before interest, taxes, depreciation, and
amortization) multiples of the comparable companies in relation to the EBITDA results of the gas reporting unit to determine an estimate of fair value.

We
also utilize a valuation technique under the income approach which estimates the discounted future cash flows of operations. Our procedures include developing a baseline test and
performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering

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those
assumptions which are subjective in nature and inherent to a discounted cash flows calculation. Other qualitative factors and comparisons to industry peers are also used to further support the
assumptions and ultimately the overall evaluation. A key qualitative assumption considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for the gas
reporting unit. Some of the key quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal
value calculations. We believe it is unlikely that a change to one of these key assumptions, by itself, would be sufficient to impact the estimated fair value determined in our discounted cash flow
calculation enough to result in an impairment charge. However, if significant negative changes occurred to multiple key assumptions, an impairment charge could result. With the exception of the
capital spending rate, the key assumptions noted are significantly determined by market factors and significant changes in market factors that impact the gas reporting unit would likely be mitigated
by our current and future regulatory rate design to some extent. Other risks and uncertainties affecting these assumptions include: management's identification of impairment indicators, changes in
business, industry, laws, technology and economic conditions. Actual results for the gas reporting unit indicate a recent decline in gas customer growth and demand, but this was anticipated in our
assumptions for purposes of the discounted cash flow calculation. Our forecasts anticipate the customer contraction will minimize in the near future and return to positive customer growth within the
next few years.

We
weight the results of the two approaches discussed above in order to estimate the fair value of the gas reporting unit. Our annual test performed as of November 30, 2009
indicated the estimated fair market value of the gas reporting unit to be 10-15% higher than its carrying value at that time. While we believe the assumptions utilized in our analysis were
reasonable, significant adverse developments in future periods could negatively impact goodwill impairment considerations, which could adversely impact earnings.

Fuel and Purchased Power

Electric Segment

Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. This amount is adjusted to reflect
regulatory treatment for our Missouri and Kansas fuel adjustment mechanisms discussed below.

The
MPSC authorized a fuel adjustment clause (FAC) for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased
power expenses used to supply energy. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost.
Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, nearly all of the off-system sales margin flows back to the customer.
Rates related to the fuel adjustment clause will be modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the
difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power
expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to
customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified.

In
our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are
subject to audit and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

final
determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if
the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations.

Similar
fuel recovery mechanisms are in place for our Oklahoma, Arkansas and the FERC jurisdictions. We buy and sell power through the SPP RTO energy imbalance services market (EIS). We
net settle these market transactions on an hourly basis.

At
December 31, 2009, our Missouri fuel and purchased power costs were under-recovered by $0.1 million, which is reflected as a regulatory asset.

We
receive Renewable Energy Credits (REC) in conjunction with our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These credits are
considered inventory and are recorded at zero cost (See Note 11).

Effective
March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management
Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary
value. We have not yet exchanged or sold any allowances. We classify our allowances as inventory and they are recorded at cost. The banked allowances are recorded at zero cost. The allowances are
removed from inventory on a FIFO basis. We consider used allowances to be a part of fuel expense (See Note 11).

Gas Segment

Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery
allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and
related carrying costs associated with the Company's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically
(up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

We
calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the
MPSC. PGA factor elements considered include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

Pursuant
to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and
carrying costs
associated with the use of financial instruments), are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel
in our electric business or sold in our natural gas business, on the volatile spot market and to manage certain interest rate exposure.

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Electric Segment

Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized
on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of
cash flows to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a
"non-hedging" instrument). Changes in the fair value of a derivative that is highly effective and designated and qualifies as a cash-flow hedge are recorded in comprehensive
income until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are recorded in earnings). Changes in the
fair value of non-hedged derivative instruments and any ineffective portion of a qualified hedge are reported in current-period earnings in fuel expense. Effective September 1,
2008, in conjunction with the implementation of the Missouri fuel adjustment clause in the July 2008 MPSC rate order, the unrealized losses or gains from new derivatives used to hedge our fuel costs
will be recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery
through our fuel adjustment mechanism. Unrealized gains and losses from cash flow hedges existing at September 1, 2008 will continue to be recorded through comprehensive income. Once settled,
the realized gain or loss will be recorded as fuel expense and be subject to the fuel adjustment clause.

We
discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer highly effective in offsetting changes in cash flows of a hedged item
(including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; (3) the derivative is no longer designated as
a hedging instrument because it is less than probable that a forecasted transaction will occur; or (4) management determines that designation of the derivative as a hedge instrument is no
longer appropriate (See Note 14).

We
also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not
subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to
market for each reporting period through income.

Gas Segment

Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved
natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account.
The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year
and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering
our costs after the annual true up period (subject to a prudency review by the MPSC).

Cash
flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postretirement Benefits

We recognize expense related to pension and other postretirement benefits as earned during the employee's period of service. Related
assets and liabilities are established based upon the funded status of

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the
plan compared to the accumulated benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may
be recognized when our unrecognized gains or losses as of the most recent measurement date exceed
10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits (effective January 1, 2005) and OPEB benefits (effective January 1,
2007), unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years.

Pensions

In our 2005 electric Missouri rate case, the MPSC ruled the Company would be allowed to recover pension costs consistent with our GAAP
policy noted above. In accordance with the rate order, we prospectively calculated the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a
result, we are allowed to record the Missouri portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. Therefore, the deferral of these costs
began in the second quarter of 2005. In our 2006 Kansas rate case, the KCC also ruled that the Company would be allowed to change the recognition of pension costs, deferring the Kansas portion of any
costs above or below the amount included in the rate case as a regulatory asset or liability.

In
the Company's agreement with the MPSC regarding the purchase of Missouri Gas by EDG, the Company was allowed to adopt this pension cost recovery methodology for EDG as well. Also, it
was agreed that the effects of purchase accounting entries related to pension and other postretirement benefits would be recoverable in future rate proceedings. Thus the fair value adjustment
acquisition entries have been recorded as regulatory assets, as these amounts are probable of recovery in future rates. The regulatory asset will be reduced by an amount equal to the difference
between the regulatory costs and the estimated GAAP costs. The difference between this total and the costs being recovered from customers will be deferred as a regulatory asset or liability in
accordance with the ASC guidance on regulated operations, and recovered over a period of five years.

Other Postretirement Benefits (OPEB)

In our 2006 Missouri rate case, the MPSC approved regulatory treatment for our OPEB costs similar to the treatment described above for
pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory
assets and liabilities as described above.

In
accordance with the guidance provided in the ASC on the Medicare Prescription Drug, Improvement and Modernization Act of 2003, the accumulated postretirement benefit obligation (APBO)
and net cost recognized for OPEB reflects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act provides for a federal subsidy, beginning in 2006,
of 28% of prescription drug costs between $250 and $5,000 for each
Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are "actuarially equivalent" to the prescription
drug benefits provided under Medicare. Equivalency must be certified annually by the Federal Government. Our plan provides prescription drug benefits that are "actuarially equivalent" to the
prescription drug benefits provided under Medicare and have been certified as such.

Additional
guidance in the ASC on employers' accounting for defined benefit pension and other postretirement plans requires an employer to recognize the over funded or under funded
status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the
year in which the

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changes
occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of
financial position, with limited exceptions. During 2008, the MPSC approved Stipulations and Agreements providing for the continuation of the pension and other postretirement employee benefits
tracking mechanism established in our 2006 and 2007 Missouri rate orders (See Note 3). This treatment will allow for future rate recovery of the obligations and as such, we record them as
regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 8).

Unamortized Debt Discount, Premium and Expense

Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs,
including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

Liability Insurance

We are primarily self-insured for workers' compensation claims, general liabilities, benefits paid under employee
healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary
by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry
excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the
cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability
claims, and workers' compensation claims are covered by a guaranteed cost policy. (See Note 11).

Other Noncurrent Liabilities

Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual
disclosure. At December 31, 2009, the balance of other noncurrent liabilities is primarily comprised of accruals for self insurance and customer advances for construction.

Cash & Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It
also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $14.1 million and
$16.1 million at December 31, 2009 and 2008, respectively.

Fuel, Material and Supplies

Fuel, material and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average
cost. These balances are as follows (in thousands):

2009

2008Electric fuel inventory

$
15,885

$
16,430Natural gas inventory


5,404


8,911Materials and supplies


22,684


23,267TOTAL

$
43,973

$
48,608


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Income Taxes

Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for
financial reporting and tax return purposes, measured using statutory tax rates. See Note 9.

Investment
tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. Remaining unamortized investment tax
credits are being amortized over remaining lives of approximately 21 years.

The
Company is working with Kansas City Power & Light to enter into an agreement with the IRS to receive our share of the $125 million in advanced coal investment tax
credits granted to the Iatan 2 facility. Our share amounts to approximately $17.7 million. We cannot predict the timing of the receipt of the credit; however, it will have no significant income
statement impact as the credit, which will reduce our tax payments, will flow to our customers over the life of the plant. The credit, which will ultimately reduce our tax liability, has been recorded
on the balance sheet under deferred charges and deferred credits.

Accounting for Uncertainty in Income Taxes

In
2006, the FASB issued guidance which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with the ASC guidance on
accounting for income taxes. We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local income
tax examinations by tax authorities for years before 2005. We adopted the provisions of this guidance on January 1, 2007. As a result of the implementation of this guidance, we recognized
approximately $54,000 of additional liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. At December 31,
2009 and 2008, our balance sheet included approximately $0.9 million and $2.2 million, respectively, of unrecognized tax benefits which would affect our effective tax rate if recognized.
We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest accrued and penalties related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

The
ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and
is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company's stock-based
compensation plans at the beginning of each respective period, or at the date of grant or award if later. Shares attributable to stock

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options
and time-vested restricted stock are excluded from the calculation of diluted earnings per share if the effect would be antidilutive.

2009

2008

2007Weighted Average Number Of SharesBasic


34,923,526


33,820,750


30,586,780Dilutive Securities:Performance-based restricted stock awards


20,513


23,680


18,997Dividend equivalents


12,122


10,981


Employee stock purchase plan


103


4,637


3,840Stock options








734Total dilutive securities


32,738


39,298


23,571Diluted weighted average number of shares


34,956,264


33,860,048


30,610,351Antidilutive Shares


117,178





48,903


Potentially
dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.

Stock-Based Compensation

We have several stock-based compensation plans, which are described in more detail in Note 4. In accordance with the ASC
guidance on stock-based compensation, we recognized compensation expense over the requisite service period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon
the fair-value of the award as of the date of issuance (See Note 4).

Recently Issued and Proposed Accounting Standards

Codification:    In June 2009, the FASB issued
an accounting pronouncement amending "Generally Accepted Accounting Principles". This pronouncement is effective for periods ending after September 15, 2009. The amendment identifies the
sources of accounting principles, and establishes the FASB Accounting Standards Codification (Codification) as the only source of authoritative accounting principles recognized by the FASB. This
pronouncement is not intended to change generally accepted accounting principles. We adopted this pronouncement on September 15, 2009. As a result of this adoption, the Financial Accounting
Standards previously listed as FASBs have been replaced with the new standards references. This change did not change the underlying principles and, therefore, had no effect on our financial
statements.

Fair Value:    We adopted new accounting guidance on fair value measurements and disclosures on
January 1, 2008. This guidance defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value
measurements. This guidance applies to other accounting pronouncements that require or permit fair value measurements. The guidance contains a scope exception for leases and other accounting
pronouncements that address fair value measurements for purposes of lease classification or measurement. The adoption of this guidance for financial assets and financial liabilities did not have a
material impact on our consolidated financial position, results of operations and cash flows. The guidance was amended to delay the effective date for all nonfinancial assets and nonfinancial
liabilities to fiscal years beginning after November 15, 2008. We adopted this portion of the guidance on January 1, 2009. The adoption of the guidance for nonfinancial

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assets
and nonfinancial liabilities did not have an effect on our consolidated financial position, results of operations or cash flows. (See Note 15).

In
April 2009, the FASB amended the fair value measurements and disclosures guidance to provide additional guidance for estimating fair value in accordance with the fair value
measurements guidance, when the volume and level of activity for an asset or liability has decreased significantly. This guidance also addresses identifying circumstances that indicate a transaction
is not orderly. The amendment was effective as of June 30, 2009. The adoption of the amendment did not have any effect on our results of operations, financial position or liquidity.

In
April 2009, the FASB also amended the financial instruments disclosure guidance, to require disclosures about fair value of financial instruments in interim financial statements, in
addition to the annual financial statements as already required by the accounting guidance. Adoption is required for interim periods ending after June 15, 2009. As the amendment provides only
disclosure requirements, the application of this standard will not have a material impact on our results of operations, financial position or liquidity.

In
September 2009, the FASB amended the accounting guidance for fair value measurements and disclosures. The amendment was issued because some investments, such as some hedge funds and
private equity funds, do not have a readily determinable fair value. This amendment allows the investor to use net asset value per share (NAV) as a practical expedient to fair value so long as the NAV
has been calculated in a manner consistent with generally accepted accounting principles for investment companies. This amendment is effective for periods ending after December 15, 2009. The
adoption of the amendment will not have any effect on our results of operations, financial position or liquidity.

In
January 2010, the FASB amended the fair value measurements and disclosures guidance to require additional disclosures about fair value measurements. The revised guidance will require
new disclosures about the transfers in and out of Level 1 and 2 measurements, including descriptions of the reasons for the transfers. Additionally, the reconciliation of Level 3
measurements will now require separate presentation of sales, issuances and settlements. This guidance for the Level 1 and 2 measurements will
be effective for periods beginning after December 15, 2009. The guidance on the Level 3 measurements will be effective for periods beginning after December 15, 2010. We do not
expect the adoption of this guidance to have any effect on our results of operations, financial position or liquidity.

Derivatives:    In April 2008, the FASB amended the guidance for derivatives and hedging to enhance
the disclosure framework. We adopted this amendment on January 1, 2009. (See Note 14 below).

Subsequent events:    In May 2009, the FASB issued accounting guidance covering subsequent events.
This guidance is effective for periods ending after June 15, 2009 and requires the disclosure of the date through which an entity has evaluated subsequent events, and whether that date
represents the date the financial statements were issued or were available to be issued. We adopted this guidance upon its issuance by the FASB. The adoption of this guidance did not have a material
effect on our financial statement disclosures.

Defined benefit plans:    In December 2008, the FASB amended the defined benefit plans' disclosure
guidance. The amendment requires additional disclosures related to pension and other postretirement benefit plan assets. The amendment is effective as of December 31, 2009 and requires
disclosure of the fair value of each major category of plan asset of a defined benefit pension or postretirement plan. In addition, employers are required to disclose information enabling users to
understand investment policies and strategies, assess the inputs and valuation techniques used to develop fair value measurements, and to

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disclose
any significant concentrations of risks within plan assets. The adoption of this amendment did not have a material effect on our results of operations, financial position or liquidity (See
Note 8 below).

Impairment:    In April 2009, the FASB amended the debt and equity securities 
subsequent measurement guidance to change the other-than-temporary impairment guidance in existing Generally Accepted Accounting Principles (GAAP) for debt securities. The
amendment provides for improved presentation and disclosure of other-than-temporary impairments of debt securities in the financial statements. This guidance was effective as
of June 30, 2009. The adoption of this amendment did not have a material effect on our results of operations, financial position or liquidity.

Consolidation:    In June 2009, the FASB amended the accounting guidance for transfers and
servicing. This amendment is effective for annual periods beginning after November 15, 2009. The amendment removes qualifying special-purpose entities (QSPE) from GAAP. Additionally, the
requirements for derecognizing financial assets have been changed, and additional disclosures about a transferor's continuing involvement in transferred financial assets will be required. We do not
expect the adoption of this amendment to have a material effect on our financial statements.

In
June 2009, the FASB also amended the accounting guidance for consolidations. This amendment is effective for annual periods beginning after November 15, 2009. The amendment
requires an entity to complete a qualitative analysis when determining who must consolidate a variable interest entity. Additionally, the amendment requires additional disclosures, and an ongoing
reassessment of who must consolidate a variable interest entity. We are evaluating the impact of the adoption of this standard; however, we do not expect the adoption of this standard to have a
material impact on our financial statements.

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2.     Property, Plant and Equipment

Our total property, plant and equipment are summarized below (in thousands).

December 31,2009

2008Electric plantProduction

$
690,768

$
594,711Transmission


203,436


197,450Distribution


651,657


625,919General(1)


74,088


72,749Electric plant


1,619,949


1,490,829Less accumulated depreciation and amortization


542,226


511,750Electric plant net of depreciation and amortization


1,077,723


979,079Construction work in progress


301,534


289,108Net electric plant


1,379,257


1,268,187Gas plant


58,180


56,282Less accumulated depreciation and amortization


6,854


4,599Gas plant net of accumulated depreciation


51,326


51,683Construction work in progress


436


291Net gas plant


51,762


51,974Water plant


10,891


10,560Less accumulated depreciation and amortization


3,664


3,396Water plant net of depreciation and amortization


7,227


7,164Construction work in progress


5


56Net water plant


7,232


7,220OtherFiber


29,564


28,481Less accumulated depreciation and amortization


8,842


7,500Non-regulated net of depreciation and amortization


20,722


20,981Construction work in progress


37


5Net non-regulated property


20,759


20,986TOTAL NET PLANT AND PROPERTY

$
1,459,010

$
1,348,367


(1)Includes
intangible property of $12.1 and $11.9 million as of December 31, 2009 and 2008, respectively, primarily related to capitalized
software. Accumulated amortization related to this property in 2009 and 2008 was $8.5 and $7.8 million respectively.


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The
table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended
December 31 (in thousands):

2009

2008

2007Provision for depreciationRegulated  Electric and Water

$
44,973

$
42,389

$
39,577Regulated  Gas


2,072


2,016


1,967Non-Regulated


1,443


1,319


1,077TOTAL


48,488


45,724


42,621Amortization(1)


5,159


9,132


11,310TOTAL

$
53,647

$
54,856

$
53,931


(1)Includes
$4.5 million, $8.2 million, and $10.4 million of regulatory amortization for 2009, 2008 and 2007, respectively. This was
granted by the MPSC effective January 1, 2007 and updated August 23, 2008.


Annual depreciation ratesElectric and water


2.9
%

3.0
%

3.0
%Gas


3.7
%

3.7
%

3.7
%Non-Regulated


5.0
%

4.8
%

4.5
%TOTAL COMPANY


3.0
%

3.0
%

3.0
%


The
table below sets forth the average depreciation rate for each class of assets for each period presented:

2009

2008

2007Annual Weighted Average Depreciation RateElectric fixed assets:Production plant


2.2
%

2.2
%

2.2
%Transmission plant


2.4
%

2.3
%

2.3
%Distribution plant


3.6
%

3.6
%

3.6
%General plant


6.1
%

6.2
%

6.1
%Water


2.7
%

2.8
%

2.7
%Gas


3.7
%

3.7
%

3.7
%Non-regulated


5.0
%

4.8
%

4.5
%


3.     Regulatory Matters

RATE MATTERS

We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Our
rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review
and approval) are determined on a "cost of service" basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on "rate
base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation and regulatory

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amortization)
of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by
depreciation, regulatory amortization and retirement of utility plant and write-off's as authorized by the utility commissions. In general, a request of new rates is made on the basis of a "rate base"
as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process
provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag
between the time we incur costs and the time when we can start recovering the costs through rates. See Note 2 for a discussion of regulatory amortization.

Electric Segment

The following table sets forth information regarding electric and water rate increases since January 1, 2007:

Jurisdiction

Date
Requested

Annual
Increase
Granted

Percent
Increase
Granted

ROE

Date
EffectiveMissouri  Electric

October 1, 2007

$
22,040,395


6.70
%

10.8
%

August 23, 2008Missouri  Electric

February 1, 2006

$
29,369,397


9.96
%

10.9
%

January 1, 2007


Missouri

2009 Rate Case

On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers
in the amount of $68.2 million, or 19.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in
new generating units at Iatan 2 and the Plum Point Generating Station. We are currently in discussions about procedures to be used in this case, including the timing of the consideration and
rate recovery of our investments in the three generating facilities and other expenditures. Due to the expected in-service delay of Iatan 2, however, we do not anticipate recovering
Iatan 2 costs in this Missouri rate case. We anticipate filing a rate case at the conclusion of this case to recover the Iatan 2 costs.

2007 Rate Case

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual
increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based
on a 10.8% return on equity. The new rates went into effect August 23, 2008.

The
order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a
$5.7 million reduction to regulatory amortization, which is the second component to support certain credit metrics of the overall change in revenue authorized by the MPSC. Regulatory
amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the
facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately
$4.5 million annually and is recorded as depreciation expense.

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The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery
of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost.
Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to
the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with accounting guidance for regulated activities, 95% of the
difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power
expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to
customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified. On April 1, 2009, we filed proposed rate schedules with the MPSC
requesting an increase of $1.9 million in revenues for the under recovered fuel costs recognized for the six month period ended February 28, 2009. This increase in revenue was approved
by the MPSC on May 21, 2009, became effective June 1, 2009 and is billed through our fuel adjustment clause. On October 1, 2009, we filed proposed rate schedules with the MPSC
requesting a decrease of $0.8 million in revenues for the over recovered fuel and purchased power costs recognized for the six month period ended August 31, 2009.

The
MPSC order in the rate case approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the
2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking
mechanism for recovery of the costs relating to the new MPSC rules on infrastructure inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any
year we spend less than the target amount, which has been set at $8.6 million for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset
and liability amounts created using the tracking mechanism will then be netted against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements
providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate orders.

The
MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed
applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective
August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff
sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

On
October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions
were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on
December 31, 2009, affirming the Commission's Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

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2006 Rate Case

All pending applications for rehearing in our Missouri 2006 rate case were denied by the MPSC on November 20, 2008. On
December 15, 2008, the OPC filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC's decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a
Petition for Writ of Review on December 19, 2008. These actions were consolidated into one proceeding. Briefs were filed by all parties and oral arguments were held on June 2, 2009. The
Cole County Circuit Court issued a ruling on December 8, 2009, affirming the MPSC's order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

On
May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the
period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a
motion to dismiss, or, in the alternative, motion for more definitive statement. On September 3, 2009, the Jasper County Circuit Court dismissed the petition with prejudice. On
October 7, 2009, the OPC appealed the Jasper County Circuit Court decision to the Missouri Court of Appeals  Southern District. The initial brief was filed by the OPC on
January 11, 2010. We filed a response brief on February 5, 2010.

Kansas

On November 4, 2009, we filed a request with the KCC for an annual increase in base rates for our Kansas electric customers in
the amount of $5.2 million, or 24.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury
plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. We anticipate new rates will go
into effect in July 2010.

Gas Segment

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the
amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity
of 11.3%. We have entered into a Stipulated Agreement, which was approved by the MPSC, for an increase of $2.6 million. Pursuant to the Agreement, new rates will go into effect on
April 1, 2010.

COMPETITION

Electric Segment

SPP-RTO

Energy Imbalance Services: On February 1, 2007, the Southwest Power Pool (SPP)
regional transmission organization (RTO) launched its energy imbalance services market (EIS). In general, the SPP RTO EIS market provides real time energy for most participating members within the SPP
regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy
imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native
load.

Day Ahead Market: The SPP and its members have been evaluating the costs and benefits on expanding the EIS market into a full day ahead
energy market with a co-optimized ancillary services market, which

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will
include the consolidation of all SPP balancing authorities, including ours, into a single SPP balancing authority. On April 28, 2009, the SPP Regional State Committee (SPP RSC), whose
members include state commissioners from our four state commissions, and the SPP Board of Directors (SPP BOD) endorsed a cost benefit report that recommended the SPP RTO move forward with the
development of a day-ahead market with unit commitment and co-optimized ancillary services market (Day-Ahead Market) and implement the complete
Day-Ahead Market as soon as practical, which is anticipated in late 2013 or early 2014. As part of the Day-Ahead Market, the SPP RTO will create, prior to implementation of
such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including us, which is expected to provide operational and economic benefits
for us and our customers. The implementation of the Day-Ahead Market will replace the existing EIS market, which to date has, and is expected to continue to, provide benefits for our
customers.

SPP Regional Transmission Development:On August 15, 2008, the SPP filed with the FERC proposed revisions to its open access
transmission pro forma tariff (OATT) to establish a process for including a "balanced portfolio" of economic transmission upgrades in the annual SPP Transmission Expansion Plan. The cost of such
upgrades will be recovered through a regional rate allocated to SPP members
based on their load ratio share within SPP's market area of the balanced portfolio's cost. On October 16, 2008, the FERC accepted the balanced portfolio approach, which sets forth the selection
process of a group of projects and regional cost allocation rules based on projected benefits and allocated costs over a ten year period. The plan will be balanced if the portfolio is cost beneficial
for each zone, including ours, within the SPP. A balanced portfolio could include projects below the 345 kv level (which is the bright line voltage level for projects to be included in the portfolio)
to increase benefits to a particular zone to achieve balance of benefits and costs over the ten year study period. On April 28, 2009, the SPP RSC and the SPP BOD approved the first set of
balanced portfolio extra high voltage transmission projects to be constructed within the SPP region. The transmission expansion projects, totaling over $700 million, include projects in
Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set of transmission expansion projects will provide long term benefits to our customers yet expect our share of the net
allocated costs to be immaterial. Also on April 28, 2009, the SPP RSC and BOD approved a new report that recommends restructuring of the SPP's regional planning processes, which would establish
an integrated planning process for reliability, transmission service and economic transmission projects, based on a new set of planning principles that focus on the construction of a more robust
transmission system large enough in both scale and geography to provide flexibility to meet SPP members' and customers' future needs. We will actively participate in the development of these new
processes as well as cost allocation and recovery issues with members, prospective customers and the state commission representatives to the SPP RSC. On October 27, 2009, the SPP BOD endorsed a
new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP
customers, including ours, well into the future. The new cost allocation method will be filed at the FERC in the second quarter of 2010. We continue to evaluate the cost and benefit impacts and our
position on the new cost allocation method to determine whether it will provide sufficient long term benefits to our customers or require modifications through the FERC approval process.

FERC Market Power Order

On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control
area based on our failure to meet one of the FERC's wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC
issued its order accepting Empire's proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders

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issued
since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff
applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, covering over 1,000 hourly energy sales since May 16,
2005 to numerous counterparties external to our system for wholesale sales made at market prices above the cost based prices permitted under the mitigation proposal accepted by the FERC. The refund
obligation applied to certain wholesale power sales made "inside" our service area at market based rates, even though consumption of the energy occurred outside our service area.

On
September 14, 2006, we filed a Request For Rehearing of the FERC's August 15, 2006 order regarding the refund and market power mitigation we had proposed. We requested a
rehearing and a waiver of the refund requirement in its entirety. On April 25, 2008, the FERC issued an Order that rejected our Request For Rehearing, required a Compliance Filing of our market
based rate tariff and ordered refunds with interest. We made our Compliance Filing and issued refunds totaling $340,608, including interest, on May 27, 2008. We also filed an informational
refund report with the FERC on June 26, 2008.

As
a result of the FERC's requirement for us to issue the aforementioned refunds and our belief that the FERC erred in its orders, on June 30, 2008 we initiated a Petition For
Review of the FERC's orders on our market based rate refunds in the United States Court of Appeals for the District of Columbia Circuit (DC Circuit). We requested and received approval for a
consolidation of our Petition with a similar petition by Westar Energy. On June 12, 2009, the DC Circuit denied our and Westar's Petition for FERC to review its Order requiring the refunds to
be made, concluding our efforts to recover the refunds paid.

As
part of our market based pricing authority, we are required to conduct a market power analysis within our service territory and within the SPP RTO region every three years. We filed
our triennial market power analysis with the FERC on July 30, 2009, concluding there were no material changes to our market position. As a result, we do not anticipate any changes to our
existing market based rate authority. The FERC's acceptance of our filing is pending.

Other FERC Activity

On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in
organized wholesale power markets, such as the SPP RTO in which we participate. On October 16, 2008, the FERC issued its Final Order on Wholesale Competition in Regions with Organized Electric
Markets. The Final Order will affect us as it directly affects the SPP RTO. The Final Order addresses four key areas for amending its regulations in Wholesale Competition for RTOs and Independent
System Operators (ISOs): (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market monitoring
policies; and (4) the responsiveness of RTOs and ISOs to stakeholders and customers. We continue to be involved in the SPP RTO and our state commission discussions on compliance of these new
rules.

On
May 21, 2009, the FERC issued an order clarifying that, going forward, small public utilities that have been granted waiver of Order No. 889 (Open Access Same Time
Information Systems (OASIS) requirement) and the Standards of Conduct for transmission operations, which includes us, are required to submit a notification filing if there has been a material change
in facts that may affect the basis on which a public utility's waiver was premised. The Standards of Conduct generally govern the communications between our day to day transmission operations
personnel and our day to day wholesale marketing and sales personnel. We submitted our filing on July 13, 2009 in which we believe continuation of our waiver, issued in 1997 and reaffirmed in
2004, is appropriate and reasonable. Based on the May 21, 2009 order, it

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is
possible that the FERC will revoke our waiver which would impact communication between our transmission and wholesale marketing and sales functions and operations within our organization. As part
of our filing, we sought a twelve month extension in order to comply with the Standard of Conduct requirements in the event the FERC determined that revoking our waiver was appropriate. The FERC's
decision on this and other Standard of Conduct waiver filings is pending.

Gas Segment

Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than
EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues
for distribution and other services if natural gas is purchased from another source by our eligible customers.

Other  Rate Matters

In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.7 million of expense
related to rate cases under other non-current assets and deferred charges of which $0.2 million is related to the 2007 Missouri rate case, $0.2 million is related to the
Missouri electric case filed October 29, 2009 and $0.2 million is related to the Missouri gas rate case filed June 5, 2009. These amounts will be amortized over varying periods
based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

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Regulatory Assets and Liabilities and Other Deferred Credits

The following table sets forth the components of our regulatory assets and regulatory liabilities on our consolidated balance sheet (in
thousands).

December 31,2009

2008Regulatory Assets:Unrecovered purchased gas costs  gas segment  current

$
434

$
1,791Unrecovered electric fuel and purchased power costs  current


338


242Regulatory assets, current(1)


772

$
2,033Pension and other postretirement benefits(2)


81,171


84,926Income taxes


49,230


34,515Storm costs(3)


11,673


14,704Unamortized loss on reacquired debt


12,167


13,490Unamortized loss on interest rate derivative


2,091


2,405Asbury five-year maintenance


1,401


1,855Deferred Iatan construction accounting costs(4)


2,732


Asset retirement obligation


3,264


3,118Unrecovered electric fuel and purchased power costs


662Unrecovered purchased gas costs  gas segment





3,787Unsettled derivative losses  electric segment


335


1,218Customer programs


1,255


591System reliability  vegetation management


1,636


654Other


637


763Regulatory assets, long-term


168,254


162,026TOTAL REGULATORY ASSETS

$
169,026

$
164,059Regulatory LiabilitiesCosts of removal

$
53,083

$
43,713Income taxes


20,678


11,126Unamortized gain on interest rate derivative


4,051


4,221Pension and other postretirement benefits(5)


6,415


7,042Over recovered electric fuel and purchased power costs(6)


1,344


228Over recovered purchased gas costs  gas segment


1,874Other


88


255TOTAL REGULATORY LIABILITIES

$
87,533

$
66,585


(1)Reflects
under recovered costs currently being recovered in Missouri rates.(2)Primarily
reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition
costs. Approximately $0.5 million in pension and other postretirement benefit costs have been recognized since January 1, 2009 to reflect the amortization of the regulatory assets that
were recorded at the time of the acquisition of the Aquila, Inc. gas properties.


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(3)Primarily
reflects ice storm costs incurred in 2007 but also includes deferred wind storm costs of $0.7 million incurred in May 2009. Consistent with
recent rate case treatment, we expect to recover wind storm costs over a five year period commencing when rates go into effect.(4)Includes
$0.8 million of deferred depreciation costs and $1.9 million in carrying costs related to construction accounting for Iatan 1
discussed below.(5)Includes
the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension
costs and the Missouri EDE portion of other postretirement benefit costs. Since January 1, 2009, regulatory liabilities and corresponding expenses have been reduced by approximately
$0.5 million as a result of ratemaking treatment.(6)Primarily
consists of Missouri over recovered fuel and purchased power costs for the current accumulation period September 2009 through February 2010.


On
April 19, 2009, we began recording deferred Iatan construction accounting costs associated with our share of the environmental upgrades recently completed at our Iatan 1
facility subsequent to the in-service date in accordance with our regulatory plan. The effect of these deferred costs, which include depreciation and a deferred carrying charge, is
reflected in regulated operating expenses, depreciation and in other interest on the statement of operations. Construction accounting, for purposes of the regulatory plan, is specific to Iatan 1 and
Iatan 2 construction and allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately
included in our rate base. The amounts deferred, which began at the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be
amortized over the life of the plants once they are in our rate base. The regulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercial operation on
April 10, 2007 at our Riverton plant, the environmental upgrades at Asbury, which were completed in 2008, environmental upgrades at Iatan 1 and the construction of the Iatan 2 facilities.

Unamortized
losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our
regulatory assets are not included in rate base, generally because they are not cash items or they are earning carrying costs. However, as of December 31, 2009, the costs of all of our
regulatory assets are currently being recovered except for the deferred Iatan costs discussed above, deferred wind storm costs incurred in May of 2009, and approximately $74.8 million of
pension and other postretirement costs primarily related to the additional liabilities for future pension and OPEB costs. The amount and timing of recovery of this item will be based on the changing
funded status of the pension and OPEB plans in future periods.

The
regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on
interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 4 to 26 years. The unrecovered fuel costs are generally recovered within a year
following their recognition. Ice storm costs and the Asbury five-year maintenance costs are recovered over five years. Pension and other postretirement benefit tracking mechanisms are
recovered over a five year period.

4.     Common Stock

Recent Issues

On
February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, as amended, we may offer and sell
shares of our common stock,

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par
value $1.00 per share, having an aggregate offering amount of up to $120 million from time to time through UBS, as sales agent. We intend to use the net proceeds from this equity
distribution program to repay short-term debt and for general corporate purposes, including to fund our current construction program. During the fourth quarter of 2009, we issued and sold
2,115,149 shares of our common stock, pursuant to this program, at an average price per share of $18.51, resulting in proceeds to us of approximately $37.9 million (after payment of
approximately $1.2 million in commissions to the sales agent). Since the inception of this program, in the aggregate, we have issued and sold 3,767,909 shares pursuant to the program, resulting
in net proceeds to us of approximately $66.7 million.

Sales
of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the program agreement, we may also
sell shares to UBS as principal for UBS' own account at a price agreed upon at the time of sale.

On
December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately
$65.8 million ($69.0 million less issuance costs of $3.2 million). The proceeds were used to pay down short-term debt incurred, in part, as a result of our ongoing
construction program.

Stock Based Compensation

We
have several stock-based awards and programs, which are described below. Performance based restricted stock awards, stock options and their related dividend equivalents are valued as
liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the
awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued
over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

We
recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in
thousands):

2009

2008

2007Compensation expense

$
2,292

$
1,841

$
2,122Tax benefit recognized


819


659


772


Stock Incentive Plans

Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and
provides for grants of up to 650,000 shares of common stock through January 2016. The 2006 Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits
Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers
applied to receive annual incentive awards related to 2008 and 2009 performance in the form of Empire common stock rather than cash. These requests were granted by the Compensation Committee of the
Board of Directors under the terms of our 2006 Stock Incentive Plan. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the
provisions of these Stock Incentive Plans.

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Performance-Based Restricted Stock Awards

Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of
common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year
period compared with an investor-owned utility peer group. The threshold level of performance under the 2007, 2008 and 2009 grants was set at the 20th percentile level of the peer
group, target at the 50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year
performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the
maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached. As noted previously, all performance-based restricted
stock awards are classified as liability instruments, which must be revalued each period until settled. The fair value of the outstanding restricted stock awards was estimated as of
December 31, 2009 and 2008 using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

Fair Value of Grants Outstanding at
December 31,2009

2008

2007Risk-free interest rate

0.47% to 1.08%

0.37% to 0.66%

4.5% to 5.09%Expected volatility of Empire stock

28.8%

26.6%

15.2% to 16.6%Expected volatility of peer group stock

22.1% to 80.9%

20.5% to 68.7%

18.9% to 19.8%Expected dividend yield on Empire stock

7.6%

6.4%

5.6% to 5.8%Expected forfeiture rates

3%

3%

3%Plan cycle

3 years

3 years

3 yearsFair value percentage

87.0% to 132.0%

99.0% to 124.0%

107.7% to 108.1%Weighted average fair value per share

$21.00

$19.23

$23.02


Non-vested
restricted stock awards (based on target number) as of December 31, 2009, 2008 and 2007 and changes during the year ended December 31, 2009, 2008 and
2007 were as follows:

2009

2008

2007Number of
Shares

Weighted
Average
Grant Date
Fair Value

Number of
Shares

Weighted
Average
Grant Date
Fair Value

Number of
Shares

Weighted
Average
Grant Date
Fair ValueOutstanding at January 1,


52,300

$
22.64


43,400

$
23.02


38,800

$
22.25Granted


13,500

$
18.12


21,000

$
21.92


17,700

$
23.81Awarded


(12,394
)
$
22.23


(6,486
)
$
22.77


(7,598
)
$
21.79Not awarded


(1,206
)
$



(5,614
)
$



(5,502
)
$
Nonvested at December 31,


52,200

$
21.57


52,300

$
22.64


43,400

$
23.02


At
December 31, 2009 and 2008, unrecognized compensation expense related to estimated outstanding awards was $0.4 million.

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Stock Options

Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable
after three years and expire ten years after the date granted. Participants' options that are not vested become forfeited when participants leave Empire except for terminations of employment under
certain specified circumstances. Dividend equivalent awards are also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year
period until the option becomes exercisable. Dividend equivalents cease to be accumulated on the date that a participant leaves Empire, and the accumulated dividend equivalents are forfeited when a
participant leaves the Company, except for terminations of employment under certain specified circumstances. The fair value per dividend
equivalent grants for 2009, 2008 and 2007 outstanding at December 31, 2009, were $3.75, $3.82 and $3.84, respectively.

The
dividend equivalents are accumulated for the three-year period and are converted to shares of common stock based on the fair market value of the shares on the date
converted. As per Section 409A of the Internal Revenue Code, added by the American Jobs Creation Act of 2004, the dividend equivalent awards vest and are payable in fully vested shares of our
common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option.

As
noted previously, all outstanding stock option awards are classified as liability instruments, which must be revalued each period until settled. Stock option grants vest upon
satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of
December 31, 2009 and 2008, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

Fair Value of Grants Outstanding at
December 31,2009

2008

2007Risk-free interest rate

1.11% to 2.98%

0.85% to 1.70%

3.3% to 4.7%Dividend yield

7.6%

6.4%

5.3% to 6.2%Expected volatility

24.0%

24.0%

15.5% to 18.1%Expected life in months

78

78

60Market value

$18.73

$17.60

n/aWeighted average fair value per option

$0.97

$0.78

$2.71


A
summary of option activity under the plan during the year ended December 31, 2009, 2008 and 2007 is presented below:

2009

2008

2007Options

Weighted
Average
Exercise
Price

Options

Weighted
Average
Exercise
Price

Options

Weighted
Average
Exercise
PriceOutstanding at January 1,


205,600

$
22.73


149,200

$
23.04


135,000

$
22.21Granted


27,000

$
18.12


56,400

$
21.92


64,200

$
23.81Exercised




$





$



(50,000
)
$
21.79Outstanding at December 31,


232,600

$
22.19


205,600

$
22.73


149,200

$
23.04Exercisable, end of year


85,000

$
22.46


43,300

$
22.67


4,200

$
21.79


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The
aggregate intrinsic value at December 31, 2009, 2008 and 2007 was immaterial. The intrinsic value of the unexercised options is the difference between the Company's closing
stock price on the last day of the period and the exercise price multiplied by the number of in-the-money options, had all option holders exercised their options on the last
day of the period.

The
range of exercise prices for the options outstanding at December 31, 2009 was $18.12 to $23.81. The weighted-average remaining contractual life of outstanding options at
December 31, 2009, 2008 and 2007 was 6.6, 7.1 and 7.6 years, respectively. As of December 31, 2009, this includes 85,000 shares at the weighted average price of $22.46, which are
vested and exercisable. All others are non-vested. As of December 31, 2009 and 2008, there was $0.2 and $0.3 million, respectively, of unrecognized compensation expense
related to non-vested options and related dividend equivalents granted under the plan.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower
of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of
December 31, 2009, there were 397,744 shares available for issuance in this plan.

2009

2008

2007Subscriptions outstanding at December 31,


68,591


48,413


40,672Maximum subscription price

$
14.62
(1)
$
18.57

$
21.23Shares of stock issued


44,265


38,803


37,686Stock issuance price

$
14.10

$
18.61

$
20.05


(1)Stock
will be issued on the closing date of the purchase period, which runs from June 1, 2009 to May 31, 2010.


Assumptions
for valuation of these shares are shown in the table below.

2009

2008

2007Weighted average fair value of grants

$
3.26

$
3.46

$
3.40Risk-free interest rate


0.48
%

2.17
%

4.98
%Dividend yield


7.90
%

6.20
%

5.43
%Expected volatility(1)


40.00
%

26.00
%

18.01
%Expected life in months


12


12


12Grant date


6/1/09


6/2/08


6/1/07


(1)One-year
historic volatility


Stock Unit Plan for Directors

Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors. This plan enhances our
ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also
provides directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible directors who had benefits under the prior cash retirement plan converted
their cash retirement benefits to common stock units.

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A
total of 400,000 shares are authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. The
number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the
units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend's record date. We record the related compensation expense at the time we make
the accrual for the directors' benefits as the directors provide services. At December 31, 2009 and 2008, there were 112,895 and 114,725 shares accrued to directors' accounts, respectively; and
317,870 and 352,722 shares available for issuance under this plan, respectively.

2009

2008

2007Units accrued for service and dividends


33,024


20,979


17,849Units redeemed for common stock


34,853


3,484


3,299


401(k) Plan and ESOP

Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up
to an Internal Revenue Service specified limit. We match 50% of each employee's deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the
employee's eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2009 and 2008, there were 169,431 and
242,839 shares available to be issued, respectively.

2009

2008

2007Shares contributed


73,408


59,253


47,563


Dividends

Holders of our common stock are entitled to dividends, if, as, and when declared by the Board of Directors, out of funds legally
available therefore subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after
considering all relevant factors, including the amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2009, our retained
earnings balance was $10.1 million, compared to $13.6 million at December 31, 2008 after paying out $44.8 million in dividends during 2009. A reduction of our dividend per
share, partially or in whole, could have an adverse effect on our common stock price. On February 4, 2010, the Board of Directors declared a quarterly dividend of $0.32 per share on common
stock payable March 15, 2010 to holders of record as of March 1, 2010.

Under
Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which
the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax.
However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the
Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the
FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive
analysis of the specific facts and circumstances surrounding the utility and the dividend in

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question,
with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

In
addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may
not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock
financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would
exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another
corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to
our shareholders by increasing the basket available to pay dividends by $10.75 million, as described above. As of December 31, 2009, this restriction did not prevent us from issuing
dividends.

In
addition, under certain circumstances, our Junior Subordinated Debentures, 81/2% Series due 2031, reflected as a note payable to securitization trust on our balance
sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if:
(1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable
steps to cure the event, (2) we are in default with respect to payments of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred
interest payments on the Junior Subordinated Debentures, 81/2% Series due 2031 or given notice of a deferral of interest payments. As of December 31, 2009, there were no such
restrictions on our ability to pay dividends.

5.     Preferred and Preference Stock

We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of
which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2009 or
2008.

Preference Stock Purchase Rights

Our shareholder rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of
common stock owned. Each Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other
securities) at a price of $75 per one one-hundredth share, subject to adjustment. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire
July 25, 2010, will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. The Rights may be redeemed by us in whole, but not in
part, for $0.01 per Right, prior to 10 days after the first public announcement of the acquisition of 10% or more of our common stock by an Acquiring Person. We had 38.0 million and
33.9 million Rights outstanding at December 31, 2009 and 2008, respectively.

In
addition, upon the occurrence of a merger or other business combination, or an event of the type referred to in the preceding paragraph, holders of the Rights, other than an Acquiring
Person, will be entitled, upon exercise of a Right, to receive either our common stock or common stock of the Acquiring

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Person
having a value equal to two times the exercise price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of our outstanding common stock, our Board of
Directors may, at their option, exchange part or all of the Rights (other than Rights held by the Acquiring Person) for our common stock on a one-for-one basis.

6.     Long-Term Debt

At December 31, 2009 and 2008, the balance of long-term debt outstanding was as follows (in thousands):

2009

2008Note payable to securitization trust(1)

$
50,000

$
50,000First mortgage bonds (EDE):81/8% Series due 2009





20,00061/2% Series due 2010


50,000


50,0007.20% Series due 2016


25,000


25,0005.3% Pollution Control Series due 2013(2)


8,000


8,0005.2% Pollution Control Series due 2013(2)


5,200


5,2005.875% Series due 2037(3)


80,000


80,0006.375% Series due 2018(3)


90,000


90,0007.0% Series due 2024(4)


74,975


First mortgage bonds (EDG):6.82% Series due 2036(3)


55,000


55,000388,175


333,200Senior Notes, 7.05% Series due 2022(2)


48,522


49,084Senior Notes, 41/2% Series due 2013(3)


98,000


98,000Senior Notes, 6.70% Series due 2033(3)


62,000


62,000Senior Notes, 5.80% Series due 2035(3)


40,000


40,000Other


5,254


334Less unamortized net discount


(774
)

(891
)691,177


631,727Less current obligations of long-term debt


(50,587
)

(20,000
)Less current obligations under capital lease


(434
)

(160
)Total long-term debt

$
640,156

$
611,567


(1)Represented
by our Junior Subordinated Debentures, 81/2% Series due 2031. We may redeem some or all of the debentures at any time at 100% of
their principal amount plus accrued and unpaid interest to the redemption date.(2)We
may redeem some or all of the notes at any time at 100% of their principal amount, plus accrued and unpaid interest to the redemption
date.(3)We
may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid
interest to the redemption date.(4)We
may redeem some or all of the bonds at any time on or after April 1, 2012, at 100% of the principal amount of the bonds plus accrued and unpaid
interest to the redemption date.


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Debt Financing Activities

On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net
proceeds (after payment of expenses) of approximately $72.6 million were used to repay short-term debt incurred, in part, to fund our current construction program.

On
May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.4 million of legal
and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction
program.

On
March 26, 2007, we issued $80 million principal amount of first mortgage bonds. The net proceeds of approximately $79.1 million, less $0.4 million of legal
and other financing fees, were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

We
have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities,
preference stock, first mortgage bonds and trust preferred securities. We have received regulatory approval in all four of our state jurisdictions. Of the $400 million, $250 million is
available for first mortgage bonds with $175 million remaining available after the issuance of $75 million in first mortgage bonds on March 27, 2009. We plan to use a portion of
the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects.

The
principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all
of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture
could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months
within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective
issue of new first mortgage bonds. Our earnings for the twelve months ended December 31, 2009 would permit us to issue approximately $239.9 million of new first mortgage bonds based on
this test with an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or
60% of net property additions. At December 31, 2009, we had retired bonds and net property additions which would enable the issuance of at least $644.8 million principal amount of bonds
if the annual interest requirements are met. As of December 31, 2009, we are in compliance with all restrictive covenants of the EDE Mortgage.

The
principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially
all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be
issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a
limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after
giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for
the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2009, these tests would not allow us to issue new first mortgage bonds.

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The carrying amount of our total debt exclusive of capital leases at December 31, 2009 was $688 million compared to a fair market value of
approximately $695 million. The carrying amount of our total debt exclusive of capital leases as of December 31, 2008 was $631.4 million, compared to a fair value of approximately
$563.8 million. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The
estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.

Payments Due By PeriodLong-Term Debt Payout Schedule
(Excluding Unamortized Discount
(in thousands)

Total

Note
Payable to
Securitization
Trust

Regulated
Entity
Debt
Obligations

Capital
Lease
Obligations2010

$
51,021

$


$
50,587

$
4342011


763





613


1502012


795





641


1542013


111,780





111,616


1642014


131








131Thereafter


527,461


50,000


475,497


1,964Total long-term debt obligations


691,951

$
50,000

$
638,954

$
2,997Less current obligations and unamortized discount


51,795Total long-term debt

$
640,156


7.     Short-Term Borrowings

At December 31, 2009, total short-term borrowings consisted of $18.5 million in commercial paper and $32 million in borrowings
from our line of credit. Short-term borrowings outstanding averaged $68.9 million and $47.7 million daily during 2009 and 2008, respectively, with the highest
month-end balances being $123.0 million and $102.0 million, respectively. The weighted average interest rates during 2009 and 2008 were 1.63% and 3.89% in each period. The
weighted average interest rate of borrowings outstanding at December 31, 2009 and 2008 was 1.05% and 2.96%, respectively.

On
March 11 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for
working capital, general corporate purposes
and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has substantially identical covenants and terms as (other
than pricing), our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010 discussed below. There were no borrowings under this agreement at December 31, 2009.

On
July 15, 2005, we entered into a $150 million unsecured revolving credit facility which was scheduled to terminate on July 15, 2010. On March 14, 2006, we
entered into the First Amended and Restated Unsecured Credit Agreement which amended and restated the $150 million unsecured revolving credit facility. The principal amount of the credit
facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy
Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was
$8.5 million as of February 1, 2010. On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated this facility
again. This agreement extends the termination

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date
of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility
accrues at a rate equal to, at our option, (i) the highest of (A) the bank's prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR
plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the
facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility increased from 0.80% to 2.70%. A facility fee is payable quarterly on the full amount of
the commitments under the facility and a usage fee is payable on the full amount of the commitments under the facility for any period in which we have drawn less than 33% of the total revolving
commitments under the facility, in each case based on our current credit ratings. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit
banks of $900,000 in the aggregate. The aggregate amount of the revolving commitments remained unchanged at $150 million and there were no other material changes to the terms of the facility.
The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which
does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest,
taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at
the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of
December 31, 2009, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other
indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There was $32.0 million of outstanding borrowings under this agreement
at December 31, 2009 and an additional $18.5 million was used to back up our outstanding commercial paper.

8.     Retirement Benefits

We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postretirement benefits, and have recorded the appropriate
liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable that the unfunded amount of these plans will be
afforded rate recovery. The tax effects of these entries, including the tax benefit of the Medicare Part D subsidy, are reflected as deferred tax assets and liabilities and regulatory
liabilities.

Annually
we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets and healthcare cost trend rate assumptions related to pension benefit
and post-retirement medical plan. We utilize an interest rate yield curve to determine an appropriate discount rate. The yield curve is constructed based on the yields on over 500
high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to
discount the annual benefit cash flows of the Empire pension plan and develop a single point discount rate matching the plan's payout structure. In evaluating these assumptions, many factors are
considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age
assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in
these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company's consolidated financial
statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end

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obligation
by rolling forward the beginning-of-year obligation using the demographic assumptions shown below. The economic assumptions are updated as of the end of the year.
All of the benefit plans have been measured as of December 31, 2009, consistent with previous years. See Note 1.

Pensions

Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are
based on years of service and the employee's average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding requirements of ERISA. We also have a
supplemental retirement program ("SERP") for designated officers of the Company, which we fund from Company funds as the benefits are paid.

The
general market declines experienced through 2008 negatively impacted the performance of our pension assets. As a result our net pension liability increased $53.2 million in
2008. The market
recovered in 2009, however our cost also increased. As a result, our net pension liability increased an additional $0.3 million in 2009. This increase was recorded as an increase in regulatory
assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. We expect future pension funding commitments to increase to at least the
level of our accrued cost, as required by our regulator. Our contribution is estimated at $12.0 million for 2010. For 2011, we will also be required to fund at least our accrued cost. The
actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2011, the performance of our pension assets during 2010.

Expected
benefit payments are as follows (in millions):

Year

Payments from Trust

Payments from
Company Funds2010

$
7.8

$
0.062011


8.3


0.062012


8.9


0.072013


9.5


0.082014


10.2


0.092015  2019

$
60.1

$
0.71


Other Postretirement Benefits (OPEB)

We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts
we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.

The
market declines experienced through 2008 also impacted our OPEB asset performance. Our net liability increased $15.5 million in 2008. The market recovered in 2009, however our
costs also increased, resulting in a $0.4 million increase in our 2009 net liability. The increase was recorded as an increase in regulatory assets as we believe it is probable of recovery
through customer rates based on rate orders received in our jurisdictions. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We
expect to be required to fund approximately $3.2 million in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Estimated
benefit payments are as follows (in millions):

Year

Payments from Trust

Expected
Federal Subsidy

Payments from
Company Funds2010

$
2.6

$
0.3

$
0.12011


2.9


0.3


0.12012


3.2


0.4


0.12013


3.5


0.4


0.12014


3.8


0.4


0.22015  2019

$
23.2

$
2.8

$
0.9


The
following tables set forth the Company's benefit plans' projected benefit obligations, the fair value of the plans' assets and the funded status (in thousands).

Reconciliation of Projected Benefit Obligations:

Pension

SERP

OPEB2009

2008

2009

2008

2009

2008Benefit obligation at beginning of year

$
154,377

$
140,353

$
2,337

$
2,006

$
61,950

$
56,455Service cost


4,612


3,568


61


57


1,830


1,651Interest cost


9,876


9,048


148


137


3,907


3,617Net actuarial (gain)/loss


8,092


8,223


92


200


3,881


2,150Plan participant's contribution














832


782Benefits and expenses paid


(7,902
)

(6,815
)

(63
)

(63
)

(2,885
)

(2,980
)Federal subsidy














396


275Benefit obligation at end of year

$
169,055

$
154,377

$
2,575

$
2,337

$
69,911

$
61,950


Reconciliation of Fair Value of Plan Assets:

Pension

SERP

OPEB2009

2008

2009

2008

2009

2008Fair value of plan assets at beginning of year

$
92,730

$
131,939

$


$


$
42,483

$
52,480Actual return on plan assets 
gain/(loss)


19,748


(32,394
)







6,799


(9,240
)Employer contribution


2,500











2,333


1,032Benefits paid


(7,902
)

(6,815
)







(2,753
)

(2,858
)Plan participant's contribution














803


753Federal subsidy














371


316Fair value of plan assets at end of year

$
107,076

$
92,730

$


$


$
50,036

$
42,483


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reconciliation of Funded Status:

Pension

SERP

OPEB2009

2008

2009

2008

2009

2008Fair value of plan assets

$
107,076

$
92,730

$


$


$
50,036

$
42,483Projected benefit obligations


(169,055
)

(154,377
)

(2,575
)

(2,337
)

(69,911
)

(61,950
)Funded status

$
(61,979
)
$
(61,647
)
$
(2,575
)
$
(2,337
)
$
(19,875
)
$
(19,467
)


The
employee pension plan accumulated benefit obligation at December 31, 2009 and 2008 is presented in the following table (in thousands):

Pension Benefits

SERP2009

2008

2009

2008Accumulated benefit obligation

$
146,826

$
135,296

$
1,864

$
1,570


Amounts
recognized in the balance sheet consist of (in thousands):

Pension

SERP

OPEB2009

2008

2009

2008

2009

2008Other current liabilities

$


$


$
62

$
165

$
127

$
135Pension and other postretirement benefit obligation

$
61,979

$
61,647

$
2,513

$
2,172

$
19,748

$
19,332


Net
periodic benefit pension cost for 2009, 2008 and 2007, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see
Note 3), is comprised of the following components (in thousands):

Net Periodic Pension Benefit Cost:

Pension

OPEB2009

2008

2007

2009

2008

2007Service cost

$
4,612

$
3,568

$
3,492

$
1,830

$
1,651

$
1,705Interest cost


9,876


9,048


8,238


3,907


3,617


3,416Expected return on plan assets


(10,379
)

(10,729
)

(10,300
)

(3,843
)

(3,750
)

(3,398
)Amortization of prior service cost(1)


604


744


588


(1,011
)

(1,011
)

(1,011
)Amortization of actuarial loss(1)


3,182


1,693


2,601


869


511


1,152Net periodic benefit cost

$
7,895

$
4,324

$
4,619

$
1,752

$
1,018

$
1,864


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Periodic Pension Benefit Cost:

SERP2009

2008

2007Service cost

$
61

$
57

$
50Interest cost


148


137


117Expected return on plan assets








Amortization of prior service cost(1)


(8
)

(8
)

(11
)Amortization of actuarial loss(1)


103


132


146Net periodic benefit cost

$
304

$
318

$
302


(1)Amounts
are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.


Our
net periodic pension benefit cost, exclusive of capitalized and deferred amounts, net of tax, as a percentage of net income for 2009, 2008 and 2007 was 9.8%, 5.9% and 6.9%,
respectively.

The
tables below present the activity in the regulatory asset accounts for the year (in thousands).

Amount RecognizedRegulatory Assets

Beginning
Balance
12/31/08

Current Year
Actuarial
(Gain)/Loss

Amortization
of Actuarial
Loss

Amortization
of Prior
Service
(Cost)/Credit

Ending
Balance
12/31/09Pension

$
67,586


(1,276
)

(3,182
)

(604
)
$
62,524SERP

$
1,221


92


(103
)

8

$
1,218OPEB

$
9,978


926


(869
)

1,011

$
11,046


The
following table presents the amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a
component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table presents those items for the employee pension plan and other
benefits plan at December 31, 2009, and the subsequent twelve-month period (in thousands):

Pension Benefits

SERP

OPEB2009

Subsequent
Period

2009

Subsequent
Period

2009

Subsequent
PeriodNet actuarial loss

$
58,948

$
4,134

$
1,274

$
127

$
18,684

$
1,377Prior service cost (benefit)


3,576


532


(56
)

(8
)

(7,638
)

(1,011
)Total

$
62,524

$
4,666

$
1,218

$
119

$
11,046

$
366


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The
measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic
costs are as follows:

Weighted-average assumptions used to determine the benefit obligation as of December 31:

Pension Benefits

OPEB2009

2008

2009

2008Discount rate


6.00
%

6.30
%

6.00
%

6.30
%Rate of compensation increase


4.50
%

4.50
%

4.50
%

4.50
%


Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:

Pension Benefits

OPEB2009

2008

2007

2009

2008

2007Discount rate


6.30
%

6.40
%

5.90
%

6.30
%

6.40
%

5.90
%Expected return on plan assets


8.50
%

8.50
%

8.50
%

7.45
%

7.45
%

7.45
%Rate of compensation increase


4.50
%

4.50
%

4.25
%

4.50
%

4.50
%

4.25
%


The
expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation.

The
assumed 2009 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 8.0%. Each trend rate decreases 0.50% through 2015 to an ultimate rate
of 5.0% in 2015 and subsequent years.

The
healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):

1% Increase

1% DecreaseEffect on total of service and interest cost


798


(648
)Effect on post-retirement benefit obligation


8,405


(6,926
)


Fair value measurements of plan assets

See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to
assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension
fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension
fund's principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the
Company's Investment Committee.

Pension

We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related
value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company's primary investment goals for pension fund assets are based around four basic elements:



The
target allocations for plan assets are 60%  80% equity securities, 20%  40% debt securities, and 0%  15% in all other types of investments.

The
following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2009 (in thousands):

Fair Value Measurements as of December 31, 2009Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

Percentage
of Plan
AssetsShort term investments

$


$
965

$


$
965


0.9
%Equity securitiesU.S. equity


40,069








40,069


37.4
%International equity


13,053








13,053


12.2
%Fixed income





29,474





29,474


27.5
%Other types of investmentsEquity long/short hedge funds








23,515


23,515


22.0
%$
53,122

$
30,439

$
23,515

$
107,076


100.0
%




Fair Value Measurements as of December 31, 2008Quoted Prices
in Active
Markets
for Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

Percentage
of Plan
AssetsShort term investments

$


$
925

$


$
925


1.0
%Equity securitiesU.S. equity


31,222








31,222


33.7
%International equity


9,671








9,671


10.4
%Fixed income





34,743





34,743


37.5
%Other types of investmentsEquity long/short hedge funds








16,169


16,169


17.4
%$
40,893

$
35,668

$
16,169

$
92,730


100.0
%


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)  December 31,

2009

2008Equity long/short
hedge funds

Equity long/short
hedge fundsBeginning Balance, January 1,

$
16,169

$
20,455Actual return on plan assets:Relating to assets still held at the reporting date


2,346


(4,286
)Relating to assets sold during the period





Purchases, sales and settlements, net


5,000


Transfers into and (out of) Level 3





Ending Balance, December 31,

$
23,515

$
16,169


Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity Oriented

Fixed Income Oriented and Real Estate

Common Stocks



Bonds

Preferred Stocks



GICs, BICs

Convertible Preferred Stocks



Corporate Bonds (minimum quality rating

Convertible Bonds



of Baa or BBB)

Covered Options



Cash-Equivalent Securities (e.g., U.S.

Hedged Equity Funds of Funds



T-Bills, Commercial Paper, etc.)

Certificates of Deposit in institutions with FDIC/FSLIC protection

Money Market Funds / Bank STIF Funds

Real Estate  Publicly Traded


The
above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Those
investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval



Privately Placed Securities



Warrants

Commodities Futures



Short Sales

Securities of Empire District



Index Options

Derivatives


OPEB

The Company's primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The
primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a
reasonable rate of return. The target allocations for plan assets are 0%  10% cash and cash equivalents, 40%  60% fixed income securities and 40%  60% in equity.
The

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

following
fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2009:

Fair Value Measurements as of December 31, 2009Quoted
Prices in
Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

Percentage
of Plan
AssetsCash & equivalents

$
1,179

$


$


$
1,179


2.4
%Fixed incomeU.S. government issues





9,307





9,307


18.6
%U.S. corporate issues





12,969





12,969


25.9
%Foreign issues





429





429


0.9
%Mutual funds  fixed income


145








145


0.3
%Equity securitiesU.S. common stocks


15,243








15,243


30.5
%Foreign Stocks


335








335


0.7
%Mutual funds  equity


10,170








10,170


20.3
%27,072


22,705





49,777Accrued interest & dividends











259


0.4
%$
50,036


100
%




Fair Value Measurements as of December 31, 2008Quoted
Prices in
Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Total

Percentage
of Plan
AssetsCash & equivalents

$
909

$


$


$
909


2.1
%Fixed incomeU.S. government issues





14,121





14,121


33.2
%U.S. corporate issues





5,432





5,432


12.8
%Foreign issues





412





412


1.0
%Mutual funds  fixed income


191








191


0.5
%Equity securitiesU.S. common stocks


13,060








13,060


30.7
%Foreign Stocks


183








183


0.4
%Mutual funds  equity


7,611








7,611


18.0
%21,954


19,965





41,919Accrued interest & dividends











564


1.3
%42,483


100
%


The
Company's guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might
adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the
managers are monitored by the Company's Investment Committee.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity

Fixed Income

Common Stocks



Cash-Equivalent Securities with a maturity

Preferred Stocks



of one-year or less

Bonds

Money Market Funds / Bank STIF Funds

Certificates of Deposit in institutions withFDIC protection

Corporate Bonds (minimum quality ratingof A)


The
above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Listed
below are those investments prohibited by the Investment Committee:

Prohibited Investments



Privately Placed Securities



Margin Transactions

Commodities Futures



Short Sales

Securities of Empire District



Index Options

Derivatives



Real Estate and Real Property

Instrumentalities in violation of the Prohibited Transactions Standards of ERISA



Restricted Stock


9.     Income Taxes

Income tax expense components for the years ended December 31 are as follows (in thousands):

2009

2008

2007Current income taxes:Federal

$
3,987

$
12,067

$
(3,788
)State


572


1,667


(540
)Total


4,559


13,734


(4,328
)Deferred income taxes:Federal


13,854


5,179


16,895State


1,973


738


2,407Total


15,827


5,917


19,302Investment tax credit amortization


(504
)

(525
)

(530
)Income tax from continuing operations


19,882


19,126


14,444Income tax from discontinued operations








39Total income tax expense

$
19,882

$
19,126

$
14,483


117

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Income Taxes

Deferred tax assets and liabilities are reflected on our consolidated balance sheet as follows (in thousands):

December 31,Deferred Income Taxes

2009

2008Non-current deferred tax liabilities, net


194,315


173,511Net deferred tax liabilities

$
194,315

$
173,511


Temporary
differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

December 31,Temporary Differences

2009

2008Deferred tax assets:Disallowed plant costs

$
1,217

$
1,127Gains on hedging transactions


1,583


1,647Plant related basis differences


19,130


14,617Regulated liabilities related to income taxes


14,297


4,017Pensions and other post-retirement benefits


14,558


15,027Other


2,301


2,008Total deferred tax assets

$
53,086

$
38,443Deferred tax liabilities:Depreciation, amortization and other plant related differences

$
191,930

$
158,142Regulated assets related to income


38,327


34,515Loss on reacquired debt


4,496


5,000Accumulated comprehensive income


929


1,114Losses on hedging transactions


836


956Deferred ice storm expenses


4,448


5,602Deferred fuel costs





2,136Amortization of intangibles


3,773


2,693Other


2,662


1,796Total deferred tax liabilities


247,401


211,954Net deferred tax liabilities

$
194,315

$
173,511


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effective Income Tax Rates

The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing
operations were as follows:

Effective Income Tax Rates

2009

2008

2007Federal statutory income tax rate


35.0
%

35.0
%

35.0
%Increase in income tax rate resulting from:State income tax (net of federal benefit)


3.1


3.1


3.1Investment tax credit amortization


(0.8)


(0.9)


(1.1)Effect of ratemaking on property related differences


(3.6)


(3.5)


(4.1)Other


(1.2)


(1.2)


(2.6)Effective income tax rate


32.5
%

32.5
%

30.3
%




Unrecognized Tax Benefits

2009

2008

2007Unrecognized tax benefits  January 1,

$
2,176,000

$
328,000

$
219,000The gross amounts of increases in unrecognized tax benefits taken during prior periods





1,957,000


109,000The gross amounts of decreases in unrecognized tax benefits taken during the period relating to positions accepted by taxing authorities





(109,000
)

Reductions to unrecognized tax benefits as a result of a lapse of the applicable statute of limitations


(1,270,000
)




Unrecognized tax benefits  December 31,

$
906,000

$
2,176,000

$
328,000


If
unrecognized tax benefits are recognized, the effective tax rate would change from 32.5% to 32.1% based on recognizing approximately $0.3 million of unrecognized benefits. The
Company recognized
interest or penalties of $(0.1) million and $0.2 million during 2009 and 2008 respectively, related to unrecognized tax benefits in other expenses and on the balance sheet. The Company does not
expect any significant changes to our unrecognized tax benefits over the next twelve months.

10.   Commonly Owned Facilities

We own a 12% undivided interest in the coal-fired Unit No. 1 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest
of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. At December 31, 2009 and 2008, our property, plant and equipment accounts
included the amounts in the following chart (in millions):

Iatan

2009

2008Cost of ownership in plant in service

$
134.6

$
50.1Accumulated Depreciation

$
36.6

$
34.7Expenditures(1)

$
9.9

$
9.2


(1)Operating
and maintenance expenditures excluding depreciation expense.


We
are entitled to 12% of the unit's available capacity and are obligated to pay for that percentage of the operating costs of the unit. KCP&L and KCP&L Greater Missouri
Operations Co. (formerly Aquila)

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

own
70% and 18% respectively, of the Unit. KCP&L operates the unit for the joint owners. In 2009 we added $54.0 million to plant in service associated with Iatan I environmental upgrades. On
June 13, 2006, we entered into an agreement with KCP&L to purchase a 12% undivided ownership interest in the new coal-fired Iatan 2. During 2009 we placed in service approximately
$22.9 million of common property expenditures associated with this construction project. See Note 11 for discussion regarding joint ownership in power plants under construction.

We
and Westar Generating, Inc, ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a 500-megawatt combined cycle unit at the State Line Power Plant
(the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are
responsible for approximately 60% of its costs. At December 31, 2009 and 2008, our property, plant and equipment accounts include the amounts in the following chart (in millions):

State Line Combined Cycle Unit

2009

2008Cost of ownership in plant in service

$
164.0

$
159.0Accumulated Depreciation

$
40.1

$
35.7Expenditures(1)

$
41.9

$
68.8


(1)Operating
and maintenance expenditures excluding depreciation expense.


All
of the dollar amounts listed above represents our ownership share of costs. Each participant must provide their own financing.

11.   Commitments and Contingencies

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has
provided accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company's
defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

On
May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment
and devastation of Plaintiff crops due to inappropriate management of the levee system around Iatan, of which we are a 12% owner. No procedural schedule has been established and we are unable to
predict the outcome of the law suit.

Coal, Natural Gas and Transportation Contracts

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas
operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be
used at our plants, the gas would be liquidated at market price. The firm physical gas and transportation commitments are as follows (in millions):

Firm physical gas and transportation contractsJanuary 1, 2010 through December 31, 2010

$
45.4January 1, 2011 through December 31, 2012


61.7January 1, 2013 through December 31, 2014


36.9January 1, 2015 and beyond


39.2


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force
Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection,
strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. Due to damage incurred in March 2009 to our Asbury rail
car unloading facility, we issued Force Majeure notices to our western coal suppliers and to the railroads, suspending western coal shipments. This relieved us of our contractual obligations to
receive shipments of coal until the railroad unloading facility was repaired and put back in service May 13, 2009. The minimum requirements for our coal and coal transportation contracts are as
follows (in millions):

Coal and coal transportation contractsJanuary 1, 2010 through December 31, 2010

$
24.8January 1, 2011 through December 31, 2012


16.1January 1, 2013 through December 31, 2014


5.0January 1, 2015 and beyond





Purchased Power

We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in
order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

We
have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $6.7 million through
May 31, 2010.

We
also have a long term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating
facility which is being built by Dynegy near Osceola, Arkansas. Construction began in the spring of 2006 and Dynegy reports that substantial completion is scheduled for summer 2010. We have the
option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. Commitments under this contract total approximately $48.0 million
through June 30, 2015. Due to the expected in-service delays of Plum Point and Iatan 2, we have arranged for sufficient alternative transmission and generating capacity to
meet our expected needs for May 2010 through July 2010. The incremental costs associated with this alternative will not have a material impact on our earnings and will be subject to our
fuel adjustment mechanism.

On
June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas.
Pursuant to the terms of the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We do
not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a
20-year average cost.

On
December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt
Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual supply under the
contract. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Annual payments can run from zero to a maximum of
approximately $16.9 million based on a 20-year average cost.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Payments
for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown
below.

New Construction

On March 14, 2006, we entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy
Station's new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for
summer 2010. Initially we will own, through an undivided interest, 50 megawatts of the project's capacity for approximately $88.0 million in direct expenditures, excluding allowance for
funds used during construction (AFUDC). We spent $83.8 million through December 31, 2009 and anticipate spending an additional $3.6 million in 2010 for construction expenses
related to our 50 megawatt ownership share of Plum Point Unit 1. All of our actual and estimated construction expenditures exclude AFUDC and property taxes, unless specified otherwise.
We also have a long-term (30 year) purchased power agreement for an additional 50 megawatts of capacity and have the option to purchase an undivided ownership interest in the 50
megawatts covered by the purchased power agreement in 2015.

On
June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the
coal-fired Iatan 2
generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. On January 13, 2010, KCP&L announced that, due to construction delays and unusually
cold weather, it currently anticipates that the in-service date of Iatan 2 will shift approximately two months from the previous schedule into the fall of 2010. KCP&L also announced
that, as the Iatan 2 project moves into the startup phase, it has commenced a cost and schedule reforecast process for Iatan 2. KCP&L notes that the results will be disclosed when the
process is completed, which it currently projects to be in the second half of the first quarter of 2010. Additionally, KCP&L also stated that it presently believes there will be no material increase
in the estimated construction cost range of Iatan 2.

Our
share of the Iatan 2 construction expenditures is expected to be in a range of approximately $218 million to $230 million. Our share of the Iatan 2 costs
through December 31, 2009 was $192.0 million. As a requirement for the air permit for Iatan 2, and to help meet requirements of the Clean Air Interstate Rule (CAIR), additional
emission control equipment was installed on Iatan 1. Our share of the Iatan 1 environmental costs was $54.0 million through December 31, 2009. KCP&L reported the equipment
had met regulatory in-service criteria as of April 19, 2009 and it is currently in service.

Based
on a late summer in-service date, we expected base rates reflecting our investments to be in effect in late 2010 as we filed a request with the MPSC on
October 29, 2009, for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request is primarily to allow us to recover
capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. We are currently in
discussions about procedures to be used in this case, including the timing of the consideration and rate recovery of our investments in the three generating facilities and other expenditures. As a
result of the delay in the project, we expect that the timing of receipt of the increase in base rates associated with Iatan 2 will be delayed.

We
also filed a request with the Kansas Corporation Commission (KCC) on November 4, 2009 for an annual increase in base rates for our Kansas electric customers in the amount of
$5.2 million, or 24.6%, primarily to allow us to recover capital expenditures associated with these investments. See Note 3 for additional discussion of our rate cases.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A
new combustion turbine previously scheduled to be installed by the summer of 2011 will be delayed until 2014 as our generation regulation needs are being met through a combination of
our existing units and the SPP energy imbalance market.

Leases

We have purchased power agreements with Cloud County Wind Farm and Elk River Wind Farm, which are considered operating leases
for GAAP purposes. Details of these agreements are disclosed in the Purchased Power section of this note.

We
also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for six
service center properties related to our gas segment. In addition, we have capital leases for certain office equipment and a unit train for our Plum Point generating facility.

The
gross amount of assets recorded under capital leases total $4.2 million at December 31, 2009.

Our
lease obligations over the next five years are as follows (in thousands):

Capital Leases2010

$
6982011


3202012


3152013


3152014


274Thereafter


2,737Total minimum payments


4,659Less amount representing maintenance


80Net minimum lease payments


4,579Less amount representing interest


1,582Present value of net minimum lease payments

$
2,997




Operating Leases2010

$
1,1892011


1,0212012


9152013


8452014


815Thereafter


3,410Total minimum payments

$
8,195


Expenses
incurred related to operating leases were $1.4 million, $1.5 million and $1.4 million for 2009, 2008, and 2007, respectively, excluding payments for wind
generated purchased power agreements. The accumulated amount of amortization for our capital leases was $0.4 million and $0.3 million at December 31, 2009 and 2008, respectively.

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Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to
hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and
other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. Environmental requirements have changed frequently and become
more stringent over time. We expect this trend to continue. While we are not in a position to estimate compliance costs for any new requirements, we expect them to be material, although recoverable in
rates.

Electric Segment

Air

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants
through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, and nitrogen
oxides (NOx). In the future they are also likely to include limits on emissions of mercury, and so-called greenhouse gases (GHG) such as carbon dioxide and methane.

Permits

Under the CAA we have obtained site operating permits, which are valid for five years, for each of our plants. We expect to receive
renewed permits for the Asbury, State Line and Energy Center plants early in 2010.

The
CAA also requires a permit, and if necessary installation of pollution control equipment, when making a major modification or a change in operation if such modification or change is
likely to cause a significant net increase in regulated emissions. In May 2008, KCPL received a Federal grand jury subpoena under the CAA requesting documents relating to capital projects at
Iatan 1. We own 12% of Iatan 1. We were informed by KCPL in September 2009 that the US Department of Justice does not intend to bring charges under the CAA in connection with
repair work, maintenance or modifications at Iatan Unit 1.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit through, among other things, a cap and trade program. Each existing
affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA), each of which allows the holder to emit one ton of SO2. Covered
utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions
are banked for future use.

In
2009, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our SO2 allowance bank is exhausted, currently estimated to be
mid-2011, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance
prices and high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars), it will likely be more economical for us to purchase SO2 allowances than to build a
scrubber at the Asbury Plant. If we were to purchase SO2 allowances, we would expect their cost to be fully recoverable in our rates.

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NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. Each of our affected units is in compliance with the NOx limits
applicable to it as currently operated.

On
January 6, 2010, the EPA proposed to lower the primary National Ambient Air Quality Standard (NAAQS) for ozone designed to protect public health and to set a secondary NAAQS
for ozone designed to protect sensitive vegetation and ecosystems. The EPA intends to issue final standards by August 31, 2010. Once final standards are set, states will be required to develop
State Implementation Plans (SIPs) which reflect these standards. Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds in the presence of sunlight.

Clean Air Interstate Rule (CAIR)

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts
to reduce emission levels of SO2 and NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas
where the Plum Point Energy Station is being constructed. Kansas is not included in CAIR and our Riverton Plant is not affected.

In
2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR
became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010.

The
CAIR requires covered states (including Missouri and Arkansas) to develop SIPs to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas have
approved SIPs and, based on these SIPs, we believe we will have excess NOx allowances for 2010 which will be banked for future use. However, SO2 allowances must be utilized at a 2:1 ratio for our
Missouri units as compared to our non-CAIR Kansas units beginning in 2010. As a result, based on current SO2 allowance usage projections, we expect to exhaust our banked allowances by
mid-2011 and, as discussed above, will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant.

In
order to meet CAIR requirements for Iatan 1 and to meet air permit requirements for Iatan 2, pollution control equipment has been installed on Iatan 1, including
a Selective Catalytic Reduction system (SCR), FGD scrubber system and baghouse. Installation was completed in April 2009 at a cost to us of approximately $54 million excluding AFUDC.
Also to meet CAIR requirements, we constructed an SCR at Asbury at a total cost of approximately $31 million excluding AFUDC.

The
EPA has announced that proposed revisions to CAIR will be published in May 2010 with the final regulations expected 12-14 months after the proposal. It is not
possible at this time to predict what the new requirements will be or their impact on our operations.

Mercury

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created
a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On
February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on
February 23, 2009. The EPA has not issued guidance to the states regarding the vacated regulation nor recommended future actions. However, the EPA has undertaken to develop emissions standards
for hazardous air pollutants including mercury from power plants under Section 112 of the CAA (maximum

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achievable
emission standards), and indicated it intends to issue a proposed rule by March 16, 2011 and a final rule by November 16, 2011.

Based
on CAMR, we installed a mercury analyzer at Asbury and installed two mercury analyzers at Riverton in 2008 in order to meet the previous monitoring compliance date of
January 1, 2009 and the Phase 1 mercury emission compliance date of January 1, 2010. We continue to operate the mercury analyzers at Riverton and Asbury in accordance with the
appropriate state environmental regulator's guidance.

CO2 Emissions

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit carbon dioxide (CO2) and/or other
greenhouse gases (GHG) which are measured in Carbon Dioxide Equivalents (CO2e).

On
September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities, including
EDG that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually. The first record keeping year is 2010 with initial reporting due in March 2011. We will
report our GHG emissions as required to the EPA in 2011. In addition, on September 30, 2009, the EPA issued the proposed "Prevention of Significant Deterioration and Title V Greenhouse
Gases Tailoring Rule" (Tailoring Rule) that would regulate GHG emissions from emitting sources that equal or exceed a threshold of 25,000 short tons of CO2e annually. The EPA proposes to issue the
final regulation in March 2010. The EPA indicated that Title V operating permits be the vehicle for regulation for existing
facilities with appropriate language inserted into the permits at renewal. New units and major modifications to existing units would be regulated under the current Prevention of Significant
Deterioration provisions of the CAA. On December 7, 2009, responding to a 2007 US Supreme Court decision that determined that GHGs constitute "air pollutants" under the CAA, the EPA issued its
final finding that GHGs threaten both the public health and the public welfare. This "endangerment" finding does not itself trigger any EPA regulations, but is a necessary predicate for the EPA to
proceed with the Tailoring Rule or other efforts to control GHGs.

LItigation
aimed at controlling GHG emissions has increased. For example, recently the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the
Fifth Circuit have ruled that certain public and private parties can pursue claims that GHG emissions constitute a public nuisance and can seek to recover alleged related damages.

Several
proposed pieces of legislation regulating emission of GHGs, including cap and trade systems, are under consideration by Congress with no consensus achieved to date. It is unclear
what effect, if any, final federal legislation will have on the EPA's ability to regulate GHG emissions from stationary sources.

Certain
states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than any federal regulations. For example, Kansas is a
participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has
announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments.

Although
there can be no guarantee and the ultimate cost of any GHG regulations can not be determined at this time, we would expect the cost of complying with any such regulations to be
recoverable in our rates.

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Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA).
Our plants are in material compliance with applicable regulations and have received necessary discharge permits.

The
Riverton Plant is affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on
February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of
the cooling water intake structure on Empire Lake's aquatic life is insignificant. In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA
regulations to the EPA. As a result, the EPA suspended the regulations and is expected to revise and re-propose the regulations by mid-2010. Under the initial regulations, we
did not expect costs associated with compliance to be material. We will reassess costs after the revised rules are complete.

Ash Ponds

We own and maintain coal ash ponds located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest
in a coal ash pond at the Iatan Generating Station. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants
before 2012. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash ponds. We do not have
sufficient information at this time to estimate additional costs that any new standards would impose on our operations. In April and May 2009, we received Information Collection Requests from
the EPA regarding our ash ponds, and have responded to such requests. All of the ash ponds are compliant with existing state and federal regulations.

The
EPA has announced its intention to propose new regulations pursuant to the Federal Resource Conservation and Recovery Act governing the management and storage of coal ash wastes, and
to determine whether to designate coal ash as a non-hazardous solid waste or as a hazardous waste. If the EPA designates it as a hazardous waste, coal ash would become subject to a variety
of hazardous waste regulations and the cost of handling, transporting, storing and disposing of the material would increase. We cannot predict with certainty the impact of any final EPA regulations on
our financial position, liquidity or results of operations at this time.

Renewable Energy

On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires
Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% in
retail sales by 2011, increasing to at least 15% by 2021. Kansas established a renewables portfolio standard (RPS) in May 2009. Also, there are currently proposals before the
U.S. Congress to adopt a national RPS which could be more strict than the Missouri or Kansas RPS.

The
Kansas Corporation Commission will issue regulations to implement its RPS by May 2010. At least 25 other states have adopted RPS programs that mandate some form of renewable
generation. Some of these RPS programs incorporate a trading system in which utilities are allowed to buy and sell renewable energy certificates (RECs) in order to comply. Additionally, RECs are
utilized by many companies in "green" marketing efforts. REC prices are driven by various market forces. We have been selling RECs and plan to continue to sell all or a portion of the RECs associated
with our contracts with

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Elk
River Windfarm, LLC and Cloud County Windfarm, LLC. With respect to the energy underlying the RECs that we sell, we may not claim that we are purchasing renewable energy for any
purpose, including for purposes of complying with the new Missouri requirements. Over time, we expect to retain some of the renewable allowances associated with these contracts to meet Missouri's RPS.
Revenues from REC sales for 2009, 2008 and 2007 were $1.7 million, $1.8 million, and $0.9 million respectively.

Gas Segment

The acquisition of our natural gas distribution assets in June 2006 involved the potential future remediation of two former
manufactured gas plant (MGP) sites. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No
remediation of this site is expected to be required in the near term. We have received a letter stating no further action is required from the MDNR with respect to Site #2 in Marshall,
Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two sites to be minimal.

12.   Segment Information

We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The
Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses subsidiary for
our fiber optics business.

As
discussed in "Note 18  Discontinued Operations", on September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service
provider. For financial reporting purposes, it has been classified as a discontinued operation and is not included in our segment information as shown below (in thousands).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.

For the year ended December 312009Electric

Gas

Other

Eliminations

TotalStatement of Income Information:Revenues

$
434,897

$
57,314

$
5,562

$
(605
)
$
497,168Depreciation and amortization


48,036


2,015


1,443





51,494Federal and state income taxes


18,484


572


826





19,882Operating income


68,414


4,634


1,447





74,495Interest income


225


403





(411
)

217Interest expense


43,173


3,959


57


(411
)

46,778Income from AFUDC (debt and equity)


14,131


2








14,133Income from continuing operations

$
39,078

$
874

$
1,344

$


$
41,296Capital Expenditures

$
145,287

$
2,256

$
1,261

$


$
148,804




2008Electric

Gas

Other

Eliminations

TotalStatement of Income Information:Revenues

$
448,248

$
65,438

$
5,005

$
(528
)
$
518,163Depreciation and amortization


50,305


1,940


1,317





53,562Federal and state income taxes


17,764


987


375





19,126Operating income


64,426


5,420


1,166





71,012Interest income


1,162


390





(495
)

1,057Interest expense


39,627


3,962


204


(495
)

43,298Income from AFUDC (debt and equity)


12,508


10








12,518Income from continuing operations

$
37,436

$
1,677

$
609

$


$
39,722Capital Expenditures

$
202,295

$
2,139

$
1,952

$


$
206,386




2007Electric

Gas

Other

Eliminations

TotalStatement of Income Information:Revenues

$
427,039

$
59,877

$
3,681

$
(437
)
$
490,160Depreciation and amortization


49,637


1,889


1,073





52,599Federal and state income taxes


13,590


572


282





14,444Operating income


60,222


4,688


656





65,566Interest income


562


375





(611
)

326Interest expense


35,782


3,957


251


(611
)

39,379Income from AFUDC (debt and equity)


7,648


17








7,665Income from continuing operations


31,836


969


376





33,181Capital Expenditures

$
188,545

$
2,024

$
4,999

$


$
195,568


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December 31, 2009Electric

Gas(1)

Other

Eliminations

TotalBalance Sheet Information:Total assets

$
1,759,415

$
134,355

$
21,907

$
(75,831
)
$
1,839,846




December 31, 2008Electric

Gas(1)

Other

Eliminations

TotalBalance Sheet Information:Total assets

$
1,621,502

$
138,788

$
22,186

$
(68,630
)
$
1,713,846


---

13.   Selected Quarterly Information (Unaudited)

The following is a summary of quarterly results for 2009 and 2008 (dollars in thousands except per share amounts):

QuartersQuarterly Results for 2009

First

Second

Third

FourthOperating revenues

$
136,015

$
112,230

$
128,053

$
120,870Operating income

$
18,655

$
16,027

$
23,677

$
16,136Net Income

$
10,913

$
7,627

$
14,829

$
7,927Basic Earning Per Share

$
0.32

$
0.22

$
0.43

$
0.22Diluted Earnings Per Share

$
0.32

$
0.22

$
0.43

$
0.22




QuartersQuarterly Results for 2008

First

Second

Third

FourthOperating revenues

$
136,946

$
111,280

$
138,685

$
131,253Operating income


14,559


12,326


28,019


16,108Net Income

$
6,990

$
4,817

$
20,180

$
7,735Basic Earning Per Share

$
0.21

$
0.14

$
0.60

$
0.23Diluted Earnings Per Share

$
0.21

$
0.14

$
0.59

$
0.23


The
sum of the quarterly earnings per share of common stock may not equal the earnings per share of common stock as computed on an annual basis due to rounding.

Earnings
for the fourth quarter of 2009 were $7.9 million, or $0.22 per share, as compared to $7.7 million, or $0.23 per share, in the fourth quarter 2008. Total revenues
decreased approximately $10.4 million (7.9%) for the fourth quarter of 2009 as compared to the fourth quarter of 2008 primarily due to milder weather in October and November of 2009 as compared
to the same period in 2008. Mostly offsetting the decrease in revenues were decreased fuel and purchased power costs and decreased natural gas costs.

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14.   Risk Management and Derivative Financial Instruments

We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating
to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our
fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ
materially from intended results.

All
derivative instruments are recognized at fair value on the balance sheet with gains and losses deferred in other comprehensive income (in stockholders' equity) for effective
instruments related to our electric segment, entered into prior to September 1, 2008. All other instruments are deferred as a regulatory asset or liability, due to our fuel recovery mechanism,
effective September 1, 2008 for our electric segment, and for our gas segment.

For
instruments entered into prior to September 1, 2008, we record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in "Fuel and purchased power"
under the operating revenue deductions section of our Statement of Income since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are
not speculative activities. Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory
and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged
item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized
immediately as fuel and purchased power expense in our Consolidated Statement of Income.

As
of December 31, 2009 and 2008, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of
December 31, (in thousands):

ASSET DERIVATIVES

Derivatives designated as hedging instruments

2009

2008Balance Sheet Classification

Fair
Value

Fair
ValueNatural gas contracts, electric segment

Current assets

$
2,233

$
1,214Non-current assets and deferred charges


2,438


6,208Derivatives not designated as hedging instruments due to regulatory accountingNatural gas contracts, gas segment

Current assets


410


1,177Non-current assets and deferred charges





226Natural gas contracts, electric segment

Current assets


139


4Non-current assets and deferred charges


87


Total derivatives assets

$
5,307

$
8,829


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LIABILITY DERIVATIVES

Derivatives designated as hedging instruments

2009

2008Balance Sheet Classification

Fair
Value

Fair
ValueNatural gas contracts, electric segment

Current liabilities

$
4,123

$
6,254Non-current liabilities and deferred credits





3,282Derivatives not designated as hedging instruments due to regulatory accountingNatural gas contracts, gas segment

Current liabilities


214


4,474Non-current liabilities and deferred credits





20Natural gas contracts, electric segment

Current liabilities





1,548Non-current liabilities and deferred credits


426


Total derivatives liabilities

$
4,763

$
15,578


Electric

A $0.3 million net of tax, unrealized gain representing the fair market value of our electric segment derivative contracts
treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of December 31, 2009. The tax effect of
$0.2 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning January 1, 2010 and
ending on September 30, 2011. At the end of each determination period, or if cash flow hedge treatment is discontinued, any gain or loss for that period related to the instrument will be
reclassified to fuel expense. As of December 31, 2009, approximately $1.9 million of unrealized losses are applicable to financial instruments which will settle within the next twelve
months. Effective September 1, 2008, in conjunction with the implementation of the Missouri fuel adjustment clause in the July 2008 MPSC rate order, the unrealized losses or gains from new cash
flow hedges are recorded in regulatory assets or liabilities. This is in accordance with ASC guidance on accounting for regulated operations, given that those regulatory assets and liabilities are
probable of recovery through our fuel adjustment mechanism. Unrealized gains and losses from cash flow hedges existing at September 1, 2008 will continue to be recorded through comprehensive
income. Once settled, the realized gain or loss will be recorded as fuel expense and be subject to the fuel adjustment clause.

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The following tables set forth the actual pre-tax gains/(losses) and the mark to market effect of unsettled positions from the qualified portion of our hedging activities for settled
contracts for the electric segment for each of the years ended December 31, (in thousands):

Derivatives in Cash Flow Hedging Relationships  Electric Segment

Amount of Gain/(Loss)
Reclassed from OCI into
Income (Effective Portion)Income Statement Classification
of Gain/(Loss) on Derivative

2009

2008Commodity contracts

Fuel and purchased power expense

$
(13,568
)
$
3,872Total Effective  Electric Segment

$
(13,568
)
$
3,872


Derivatives in Cash Flow Hedging Relationships  Electric Segment

Amount of Gain/(Loss)
Recognized in OCI
on Derivative
(Effective Portion)Statement of Comprehensive Income

2009

2008Commodity contracts

Fuel and purchased power expense

$
9,576

$
(17,394
)Total Effective  Electric Segment

$
9,576

$
(17,394
)


The
following table sets forth "mark-to-market" pre-tax gains/(losses) from the ineffective portion of our hedging activities for the electric segment
for each of the years ended December 31, (in thousands):

Derivatives in Cash Flow Hedging Relationships  Electric Segment

Amount of Gain/(Loss)
Recognized in Income
on Derivative-
(Ineffective Portion)Statement of Income Classification
of Gain/(Loss) on Derivative

2009

2008Commodity contracts

Fuel and purchased power expense

$


$
32Total Ineffective  Electric Segment

$


$
32


In
accordance with the Missouri fuel adjustment clause discussed above, the recoverable portion of any gain or loss is recorded in a regulatory asset or liability account. The following
tables set forth "mark-to-market" pre-tax gains/ (losses) from derivatives not designated as hedging instruments for the electric segment for each of the years
ended December 31, (in thousands):

Derivatives Not Designated as Hedging Instruments  Due to Regulatory Accounting Electric Segment

Amount of Gain/(Loss)
Recognized on
Balance SheetBalance Sheet Classification
of Gain/(Loss) on Derivative

2009

2008Commodity contracts  electric segment

Regulatory (assets)/liabilities

$
1,192

$
(1,215
)Total  Electric Segment

$
1,192

$
(1,215
)


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Derivatives Not Designated as Hedging Instruments  Due to Regulatory Accounting Electric Segment(1)

Amount of Gain/(Loss)
Recognized in Income
on DerivativeStatement of Operations Classification
of Gain/(Loss) on Derivative

2009

2008Commodity contracts

Fuel and purchased power expense

$
(2,249
)
$
(329
)Total  Electric Segment

$
(2,249
)
$
(329
)


(1)All
of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. If
conditions change, such as a planned unit outage, we may need to de-designate and/or unwind some of our previous derivatives. In this instance, these derivatives would be classified into
the category above.


We
also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to fair value accounting because they
are not derivatives because they are considered to be normal purchases. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchases
exception contain a price adjustment feature and will account for these contracts accordingly.

As
of February 5, 2010, 77% of our anticipated volume of natural gas usage for our electric operations for the year 2010 is hedged, either through physical (3.5 million
Dths) or financial contracts (3.0 million Dths), at an average price of $6.322 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas
usage for our electric operations for the next three years are hedged at the following average prices per Dth:

Year

% Hedged

Dth Hedged

Average Price2011(1)


71
%

5,115,000

$
5.8402012(1)


40
%

3,085,000

$
7.0162013


17
%

1,200,000

$
7.295


(1)2.0 million
Dth and 1.4 million Dth of the anticipated volume of natural gas usage for 2011 and 2012, respectively, are hedged through
financial derivative contracts.


We
utilize the following procurement guidelines for our electric segment: current year up to 100% of expected gas usage, first year minimum of 60%, second year minimum of 40%, third year
minimum of 20% and fourth year minimum of 10%, subject to a maximum of 80% of the expected gas usage in any one year.

On
February 15, 2008, we unwound 992,000 Dth of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This transaction resulted in a gain
of approximately
$1.3 million after tax which was recorded as a reduction to fuel and purchased power expense in the Statement of Income in the first quarter of 2008. We believe it is probable that we will take
physical delivery under the remaining physical gas forward contracts.

As
of June 30, 2007, we elected to change our valuation of natural gas derivatives (financial hedges) for financial reporting purposes to a new methodology which is more closely
related to an independent market valuation. For accounting purposes, this change is considered a change in estimate. To reflect the change, an increase of approximately $6 million was recorded
to the fair value of derivatives and $3.7 million, net of tax, was recorded to other comprehensive income at June 30, 2007. This change had no impact on the income statement.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Gas

We
attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months,
(2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. As of February 5, 2010, we have 91% of our expected remaining winter heating season
usage (through March 2010) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is $3.948 per Dth. We target to have 95% of
our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of February 7, 2010, we
had 0.70 million Dths in storage on the three pipelines that serve our customers. This represents 33% of our storage capacity. We have an additional 0.6 million Dth hedged through
financial derivatives and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of
second year and up to 20% of third year expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased Gas Adjustment (PGA) clause is included in our
rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or
regulatory liability account on our balance sheet.

The
following table sets forth "mark-to-market" pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment
for the years ended December 31, (in thousands):

Derivatives Not Designated as Hedging Instruments Due to Regulatory Accounting  Gas Segment

Amount of Gain/(Loss)
Recognized on
Balance SheetBalance Sheet Classification
of Gain or (Loss) on Derivative

2009

2008Commodity contracts

Regulatory (assets)/liabilities

$
(671
)
$
(8,939
)Total  Gas Segment

$
(671
)
$
(8,939
)


Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit
rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could
request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related
contingent features that are in a liability position on December 31, 2009 is $2.4 million for which we have posted no collateral in the normal course of business. If the
credit-risk-related contingent features underlying these agreements were triggered on December 31, 2009, we would have been required to post $0.4 million of
collateral with one of our counterparties. On December 31, 2009, we had no collateral posted with this counterparty.

15.   Fair Value Measurements

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair
value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in
active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

inputs
in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs
provided by a third party that are derived principally from or corroborated by observable market data by correlation. Our Level 3 fair value measurements consist of both quoted price inputs and
unobservable quoted inputs provided by a third party.

The
guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore,
using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral)
into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

The
following fair value hierarchy table presents information about our derivative assets measured at fair value using the market value approach on a recurring basis as of
December 31, 2009:

Fair Value Measurements at Reporting Date Using

($ in 000's)
Description

Assets/(Liabilities)
at Fair Value

Quoted Prices
in Active Markets
for Identical
Assets
(Level 1)

Significant Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)December 31, 2009Net derivative assets/(liabilities)*

$
544

$
544





December 31, 2008Net derivative assets/(liabilities)*

$
(6,749
)
$
(14,117
)
$
1,160

$
6,208


*The
only recurring measurements are derivative related and assets and liabilities are netted together in the table above.


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)




The
following tables present the net fair value on a recurring basis using significant unobservable inputs (Level 3) during the twelve months ended December 31, 2009 and
2008 (in thousands):

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

($ in 000's)

2009
Net
Derivatives(1)

2008
Net
Derivatives(1)Beginning Balance, January 1,

$
6,208

$
11,961Total gains or losses (realized/unrealized)Included in earnings (or changes in net assets)





Included in comprehensive income


(1,738
)

(5,753
)Purchases, issuances, and settlements, net





Transfers in and/or out of Level 3


(4,470
)

Ending Balance, December 31,

$


$
6,208Changes in unrealized Gains (Losses) relating to assets still held at reporting date

$
1,738

$
5,753


(1)Net
derivatives at December 31, 2009 and 2008 included zero and $6.2 million in derivative assets and no derivative liabilities, respectively.


16.   Accounts Receivable  Other

The following table sets forth the major components comprising "accounts receivable  other" on our consolidated balance sheet (in thousands):

December 31,2009

2008Accounts receivable for meter loops, meter bases, line extensions,
highway projects, etc.

$
2,812

$
803Accounts receivable for gas segment


37


76Accounts receivable for non-regulated subsidiary companies


454


287Accounts receivable from Westar Generating, Inc., for commonly-owned facility


817


1,673Taxes receivable  overpayment of estimated income taxes


3,191


4,503Accounts receivable for energy trading margin deposit(1)


2,914


10,768Accounts receivable for true-up on maintenance contracts(2)


1,831


1,138Accounts receivable for insurance proceeds for SLCC generator failure(3)


9,270


Other


91


105Total Accounts Receivable  Other

$
21,417

$
19,353


(1)The
accounts receivable for energy trading margin deposit represents the balance in our brokerage account. NYMEX futures contracts are used in our hedging
program of natural gas which require posting of margin.(2)Represents
quarterly estimated credits due from Siemens Westinghouse related to our maintenance contract for State Line Combined Cycle Unit (SLCC). Forty
percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(3)Represents
the insurance proceeds for the failure of the State Line Combined Cycle Unit 2-1 generator. Forty percent of these proceeds belong to
Westar Generating, Inc., and is recorded in accounts payable.


17.   Regulated Operating Expense

The following table sets forth the major components comprising "regulated operating expenses" under "Operating Revenue Deductions" on our consolidated statements
of income for the years ended (in thousands):

December 31,2009

2008

2007Electric transmission and distribution expense

$
11,063

$
10,891

$
9,465Natural gas transmission and distribution expense


2,161


1,995


1,755Power operation expense (other than fuel)


12,315


11,671


10,417Customer accounts & assistance expense


10,597


10,166


9,198Employee pension expense(1)


5,557


5,892


6,553Employee healthcare plan(1)


5,908


7,136


7,899General office supplies and expense


10,070


9,330


10,294Administrative and general expense


12,211


11,728


10,872Bad debt expense


3,125


2,944


4,673Miscellaneous expense


79


165


241Total

$
73,086

$
71,918

$
71,367


(1)Does
not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to a regulatory asset or recognized as a
regulatory liability for Missouri and Kansas jurisdictions.


18.   Discontinued Operations

On
September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. We have reported its results as discontinued operations. A summary of
the components of losses from discontinued operations for the year ended December 31, 2007 follows (in thousands):

2007

Fast FreedomRevenues

$
905Expenses


1,063Losses from discontinued operations before income taxes


(158
)Gain on disposal


161Income tax


60Gain from Discontinued Operations

$
63


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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of
our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined
in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls
and procedures were effective as of December 31, 2009.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is
defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we
conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.

Audit of Internal Control Over Financial Reporting

The effectiveness of our internal control over financial reporting as of December 31, 2009, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2009 that have
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Except as set forth below, the information required by this Item may be found in our proxy statement for our Annual Meeting of
Stockholders to be held April 29, 2010, which is incorporated herein by reference.

Pursuant
to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers
is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers and Other Officers of Empire."

We
have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. A copy of the code is available on our website at www.empiredistrict.com. Any future
amendments or waivers to the code will be posted on our website at www.empiredistrict.com.

ITEM 11.    EXECUTIVE COMPENSATION

Information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held
April 29, 2010, which is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Except as set forth below, information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders
to be held April 29, 2010, which is incorporated herein by reference.

There
are no arrangements the operation of which may at a subsequent date result in a change in control of Empire.

Securities Authorized For Issuance Under Equity Compensation Plans

We have four equity compensation plans, all of which have been approved by shareholders, the 1996 Stock Incentive Plan, the 2006 Stock
Incentive Plan, the Employee Stock Purchase Plan (ESPP) and the Stock Unit Plan for Directors.

The
following table summarizes information about our equity compensation plans as of December 31, 2009:

Plan Category

(a) Number of securities
to be issued upon exercise
of outstanding options,
warrants and rights.

(b) Weighted-average
exercise price
of outstanding options,
warrants and rights(1)

(c) Number of securities
remaining available
for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))Equity compensation plans approved by security holders


518,486

$
20.47


1,330,680Equity compensation plans not approved by security holders








TOTAL


518,486

$
20.47


1,330,680


(1)The
weighted average exercise price of $20.47 relates to 39,100 and 4,200 options granted to executive officers in 2005 and 2004, respectively, under the
1996 Stock Incentive Plan, 27,000, 56,400, 64,200 and 41,700 options granted to executive officers in 2009, 2008, 2007 and 2006, respectively, under the 2006 Stock Incentive Plan and 68,591
subscriptions outstanding for our ESPP. The two stock incentive plans had a weighted average exercise price of $22.19 and the ESPP had an exercise price of $14.62. There is no exercise price for
104,400 performance-based stock awards awarded under the 2006 Stock Incentive Plans or for 112,895 units awarded under the Stock Unit Plan for Directors.


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ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held
April 29, 2010 which is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held
April 29, 2010 which is incorporated herein by reference.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Index to Financial Statements and Financial Statement Schedule Covered by Report of  Independent Registered Public Accounting Firm



Consolidated balance sheets at December 31, 2009 and 2008


68Consolidated statements of income for each of the three years in the period ended December 31, 2009


70Consolidated statements of comprehensive income for each of the three years in the period ended December 31,
2009


71Consolidated statements of common stockholders' equity for each of the three years in the period ended December 31,
2009


72Consolidated statements of cash flows for each of the three years in the period ended December 31, 2009


73Notes to consolidated financial statements


75Schedule for the years ended December 31, 2009, 2008 and 2007:Schedule II  Valuation and qualifying accounts


147


All
other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial
statements or notes thereto.

List of Exhibits

(3)(a)

The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to Registration Statement No. 33-54539 on Form S-3).(b)

By-laws of Empire as amended October 31, 2002 (Incorporated by reference to Exhibit 4(b) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368).(4)(a)

Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto among Empire, The Bank of New York Mellon Trust Company, N.A. and UMB Bank, N.A., (Incorporated by
reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368).(b)

Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).(c)

Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).(d)

Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Registration Statement No. 33-56635 on Form S-3).(e)

Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-3368).(f)

Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-3368).


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(g)

Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for the year ended
December 31, 1993, File No. 1-3368).(h)

Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for the year ended
December 31, 1996, File No. 1-3368).(i)

Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File
No. 1-3368).(j)

Thirty-First Supplemental Indenture dated as of March 26, 2007 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated March 26,
2007 and filed March 28, 2007, File No. 1-3368).(k)

Thirty-Second Supplemental Indenture dated as of March 11, 2008 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated March 11,
2008 and filed March 12, 2008, File No. 1-3368).(l)

Thirty-Third Supplemental Indenture dated as of May 16, 2008 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 16, 2008
and filed May 16, 2008, File No. 1-3368).(m)

Thirty-Fourth Supplemental Indenture, dated as of March 27, 2009, to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated March 27,
2009 and filed March 30, 2009, File No. 1-3368).(n)

Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank, National Association (Incorporated by reference to Exhibit 4(v) to Registration Statement
No. 333-87015 on Form S-3).(o)

Securities Resolution No. 2, dated as of February 22, 2001, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for
the year ended December 31, 2000, File No. 1-3368).(p)

Securities Resolution No. 3, dated as of December 18, 2002, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for
year ended December 31, 2002, File No. 1-3368).(q)

Securities Resolution No. 4, dated as of June 10, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K dated
June 10, 2003 and filed July 29, 2003, File No. 1-3368).(r)

Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for
quarter ended September 30, 2003), File No. 1-3368).(s)

Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated
June 27, 2005 and filed June 28, 2005, File No. 1-3368).(t)

Rights Agreement dated as of April 27, 2000 between Empire and Wells Fargo Bank, N.A. (as successor to Chase Mellon Shareholder Services LLC) (Incorporated by reference to Exhibit 4 to Quarterly Report
on Form 10-Q for the quarter ended March 31, 2000, File No. 1-3368).


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(u)

Bond Purchase Agreement dated June 1, 2006 among The Empire District Gas Company and the purchasers party thereto (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 1,
2006 and filed June 6, 2006, File No. 1-3368).(v)

Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company,
 N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).(w)

First Supplemental Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New
York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).(10)(a)

1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639).(b)

First Amendment to 1996 Stock Incentive Plan. (Incorporated by reference to Exhibit 10(b) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).(c)

2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File No. 333-130075).(d)

First Amendment to 2006 Stock Incentive Plan. (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).(e)

Second Amendment to 2006 Stock Incentive Plan (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-3368).(f)

Deferred Compensation Plan for Directors as amended and restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for the year ended December 31,
 2007). (g)

The Empire District Electric Company Change in Control Severance Pay Plan as amended and restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(f) to Annual Report on Form 10-K
for the year ended December 31, 2007, File No. 1-3368).(h)

Form of Severance Pay Agreement under The Empire District Electric Company Change in Control Severance Pay Plan. (Incorporated by reference to Exhibit 10(g) to Annual Report on Form 10-K for the year ended
December 31, 2007, File No. 1-3368).(i)

The Empire District Electric Company Supplemental Executive Retirement Plan as amended and restated effective January 1, 2008. (Incorporated by reference to Exhibit 10(h) to Annual Report on Form 10-K
for the year ended December 31, 2007, File No. 1-3368).(j)

Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 1998, File No. 1-3368).(k)

Stock Unit Plan for Directors of The Empire District Electric Company (Incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended December 31, 2005, File
No. 1-3368).(l)

First Amendment to Stock Unit Plan for Directors. (Incorporated by reference to Exhibit 10(k) to Annual Report on Form 10-K for the year ended December 31, 2007, File
No. 1-3368).


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(m)

Summary of Annual Incentive Plan. (Incorporated by reference to Exhibit 10(l) to Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-3368).(n)

Form of Notice of Award of Dividend Equivalents. (Incorporated by reference to Exhibit 10(n) to Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-3368)(o)

Form of Notice of Award of Non-Qualified Stock Options. (Incorporated by reference to Exhibit 10(o) to Annual Report on Form 10-K for the year ended December 31, 2008, File
No. 1-3368).(p)

Form of Notice of Award of Performance-Based Restricted Stock. (Incorporated by reference to Exhibit 10(p) to Annual Report on Form 10-K for the year ended December 31, 2008, File
No. 1-3368).(q)

Summary of Compensation of Non-Employee Directors. (Incorporated by reference to Exhibit 10(q) to Annual Report on Form 10-K for the year ended December 31, 2008, File
No. 1-3368).(r)

Form of Indemnity Agreement (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated February 5, 2009 and filed February 10, 2009, File No. 1-3368).(s)

Equity Distribution Agreement dated February 25, 2009 between The Empire District Electric Company and UBS Securities LLC (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K
dated February 25, 2009 and filed February 26, 2009, File No. 1-3368).(t)

Amendment No. 1, dated October 22, 2009 to the Equity Distribution Agreement dated February 25, 2009 between The Empire District Electric Company and UBS Securities LLC (Incorporated by reference
to Exhibit 10.1 to Current Report on Form 8-K dated October 22, 2009 and filed October 22, 2009, File No. 1-3368).(u)

Unsecured Credit Agreement dated as of March 11, 2009, among The Empire District Electric Company, UMB Bank, N.A. as administrative agent, Bank of America, N.A., as syndication agent, Wells Fargo Bank, N.A., as
documentation agent, and the lenders named therein (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated March 11, 2009 and filed March 12, 2009, File No. 1-3368).(v)

Second Amended and Restated Unsecured Credit Agreement dated as of January 26, 2010, among The Empire District Electric Company, UMB Bank, N.A. as administrative agent, Bank of America, N.A., as syndication
agent, Wells Fargo Bank, N.A., as documentation agent, and the lenders named therein (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated January 26, 2010 and filed January 27, 2010, File
No. 1-3368).(12)

Computation of Ratios of Earnings to Fixed Charges.*(21)

Subsidiaries of Empire.*(23)

Consent of PricewaterhouseCoopers LLP.*(24)

Powers of Attorney.*(31)(a)

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*(31)(b)

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*


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(32)(a)

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~(32)(b)

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~


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SCHEDULE II

Valuation and Qualifying AccountsYears ended December 31, 2009, 2008 and 2007:

Additions

Deductions From ReserveCharged to Other AccountsBalance At
Beginning
Of Period

Charged
To Income

Description

Amount

Description

Amount

Balance At
Close of
PeriodYear endedDecember 31, 2009:Reserve deducted from assets:
accumulated provision for uncollectible accounts.

$
1,265,421

$
3,109,679

Recovery of
amounts previously
written off

$
1,531,820

Accounts written off

$
4,820,067

$
1,086,853Year endedDecember 31, 2008:Reserve deducted from assets:
accumulated provision for uncollectible accounts.

$
1,140,955

$
2,903,922

Recovery of
amounts previously
written off

$
1,877,576

Accounts written off

$
4,657,032

$
1,265,421Year endedDecember 31, 2007:Reserve deducted from assets:
accumulated provision for uncollectible accounts.

$
1,180,577

$
4,661,439

Recovery of
amounts previously
written off

$
1,203,544

Accounts written off

$
5,904,605

$
1,140,955


147

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE EMPIRE DISTRICT ELECTRIC COMPANYDate: February 19, 2010

By

/s/ WILLIAM L. GIPSON William L. Gipson, President and
Chief Executive Officer


Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on
the date indicated.

/s/ WILLIAM L. GIPSON William L. Gipson, President,
Chief Executive Officer, Director
(Principal Executive Officer)

Date: February 19, 2010/s/ GREGORY A. KNAPP Gregory A. Knapp, Vice President-Finance
(Principal Financial Officer)/s/ LAURIE A. DELANO Laurie A. Delano, Controller, Assistant
Secretary and Assistant Treasurer
(Principal Accounting Officer)/s/ DR. JULIO S. LEON* Dr. Julio S. Leon, Director/s/ KENNETH R. ALLEN* Kenneth R. Allen, Director/s/ PAUL R. PORTNEY* Paul R. Portney, Director/s/ ROSS C. HARTLEY* Ross C. Hartley, Director/s/ D. RANDY LANEY* D. Randy Laney, Director/s/ BILL D. HELTON* Bill D. Helton, Director/s/ B. THOMAS MUELLER* B. Thomas Mueller, Director/s/ ALLAN T. THOMS* Allan T. Thoms, Director/s/ BONNIE C. LIND* Bonnie C. Lind, Director/s/ GREGORY A. KNAPP *By (Gregory A. Knapp, As attorney in fact for
each of the persons indicated)


148

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